TEXACO ANNUAL REPORT

In an era of change intelligence prevails. A destabilized world economy... A financial crisis that devastated the economies of Asia spread in successive waves to Russia and Latin America, slashing world gross domestic product growth from a robust 4% increase in 1997 to a meager 1.6% increase in 1998. slowed growth in the demand for oil... Annual growth in world oil demand slowed abruptly, from 2 million barrels per day in 1997 to about 400,000 barrels per day in 1998. increased oil inventories... OPEC and some non-OPEC producers cut production in the second half of 1998, but year-end oil stocks were at least 200 million barrels higher than normal. and contributed to falling oil prices. Crude oil prices plunged by 30% from 1997. These were the facts of life for everyone in the energy business during 1998. But the energy business is volatile and cyclical by nature.The question is not if there will be tough times, but how to keep adding value in spite of tough times.At Texaco we have a clear vision of what needs to be accomplished, an abundant supply of human and intellectual energy, and the will to get the job done.

Peter I. Bijur Chairman of the Board and Chief Executive Officer The energy within us The challenge of today’s market conditions isn’t just in the fields or at the gasoline pumps. It exists throughout Texaco, and it’s being met with a powerful investment in human energy. We’re using tech- nology to reduce the cost of finding and developing oil and gas.We’re reorganizing upstream operations to maximize value from existing fields and run leaner. We’re focusing on higher-return projects and adding to our reserve base. We’ve entered into joint ventures to strengthen our downstream position.And we’re developing a gener- ation of new and diverse leaders at all levels of our company.

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27,562 feet

Deeper than most can dream To reach oil, we drill almost as deep as Mount Everest is high. If that sounds like a stretch, consider the lengths Texaco people go to find the oil that fuels an energy-hungry world: We were among the first in the Gulf of Mexico to drill a multilateral well, a technique that simulta- neously taps oil-bearing strata in several directions from a single pipe. Where waters are especially deep and platform construction is pro- hibitively expensive, our remote-operated subsea production systems connect to processing facilities up to 28 miles away.And our platform sits atop 27,562 feet of pipe, connecting us to oil fields that were once economically and physically unreachable. 6

Reduce, reuse, recycle Because Texaco benefits from the world’s natural resources, we have an obligation to find and use those resources with utmost care and efficiency. Reducing, reusing and recycling are not only the right things to do, they are good business. Our operations now help irrigate deserts and illuminate cities: In California, we’re treating millions of gallons of water a day as part of our extraction process to help grow crops in the parched San Joaquin Valley. We’re using cogeneration — producing electrical power and steam from a single energy source — to convert fuels such as natural gas to electricity for home and industrial use.Worldwide, our leading gasification tech- nology enables refiners, utilities and others to make fuel, power and chemical products more efficiently, reducing emissions and waste. Virtual exploration, real rewards Texaco exploration teams take their hunt for oil and gas indoors, equipped with the world’s best data and technology. Over land, infor- mation is gathered by aircraft outfitted with ground-penetrating radar and electromagnetic scanners. At sea, data from reflected sound waves are collected by mobile hydrophone buoys that Texaco adapted from Cold War-era submarine-detection technology.Texaco geoscientists model these data into clear, 3-D images, pinpointing high- potential oil and gas deposits. “Seeing” into the Earth before drilling means a massive reduction in time and cost. What used to take weeks and months now takes hours and days. In the field, “ virtual” exploration is yielding outstanding results, discovering real oil and natural gas from the United States to Trinidad, West Africa and the Middle East.

7 100% lean Texaco now competes in some markets where a gallon of gasoline costs less than a gallon of milk.That stark fact underscores the chal- lenge Texaco and our industry face: how to maintain acceptable returns during a low-price cycle.The answer is to drive costs lower and maximize the return on assets wherever possible.While our oil and gas production was up 9% in 1998 and has grown by a total of 19% since 1995, we’re still reducing our overhead and production costs. Our lifting costs and our finding and development costs already rank among the industry’s best.

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Priming the pump Texaco and its joint venture partners Shell and Saudi Refining, Inc. are together the largest gasoline marketers in the U.S., with approximately 23,600 outlets and a 15 percent market share. These alliances — Equilon Enterprises and Motiva Enterprises — are on their way to capturing about $800 million in annual savings (over $300 million for Texaco alone) that we anticipated when we created them in 1998.With Chevron, our Fuel and Marine Marketing joint venture is expected to yield more efficiency and growth opportuni- ties. Globally, our longstanding Caltex affiliate, whose 13 refineries in 10 countries support about 8,000 retail outlets, is reorganizing to improve its competitiveness in the Asia-Pacific market and save Texaco $25 million annually. 10

Financial Highlights

(Millions of dollars, except per share amounts in dollars and ratio data) 1998 1997 Revenues $ 31,707 $ 46,667 Income before special items and cumulative effect of accounting change $ 894 $ 1,894 Diluted per common share $ 1.59 $ 3.45 Return on average capital employed 6.5% 13.0% Net income $ 578 $ 2,664 Diluted per common share $ .99 $ 4.87 Return on average capital employed before cumulative effect of accounting change 5.0% 17.3% Cash dividends paid Common $ 952 $ 918 Per share $ 1.80 $ 1.75 Preferred $ 53 $ 55 Total assets $ 28,570 $ 29,600 Total debt $ 7,291 $ 6,392 Stockholders’ equity $ 11,833 $ 12,766 Capital and exploratory expenditures $ 4,019 $ 5,930 Per common share Common stockholders’ equity $ 21.24 $ 22.75 Market price at year-end $ 53.00 $ 54.38 Return on average stockholders’ equity before cumulative effect of accounting change 4.9% 23.5% Total debt to total borrowed and invested capital 36.8% 32.3%

TOTAL REVENUES CAPITAL AND TOTAL DEBT TO TOTAL (Billions of dollars) EXPLORATORY EXPENDITURES BORROWED AND INVESTED CAPITAL (Billions of dollars) (Percent) $50 $6.0 40%

$40 $4.8 32%

$30 $3.6 24%

$20 $2.4 16%

$10 $1.2 8%

1996 1997 1998 1996 1997 1998 1996 1997 1998 TEXACO 1998 ANNUAL REPORT 11

Operational Highlights

1998 1997 Net production of crude oil and natural gas liquids (Thousands of barrels a day) United States 433 396 International 497 437 Total 930 833 Net production of natural gas – available for sale (Millions of cubic feet a day) United States 1,679 1,706 International 548 471 Total 2,227 2,177 Natural gas sales (Millions of cubic feet a day) United States 3,873 3,584 International 664 592 Total 4,537 4,176 Refinery input (Thousands of barrels a day) United States 698 747 International 832 804 Total 1,530 1,551 Refined product sales (Thousands of barrels a day) United States 1,203 1,022 International 1,685 1,563 Total 2,888 2,585 Worldwide net proved reserves as of year-end Crude oil and natural gas liquids (Millions of barrels) 3,573 3,267 Natural gas (Billions of cubic feet) 6,517 6,242

NET PRODUCTION OF NET PRODUCTION OF WORLDWIDE NET PROVED RESERVES CRUDE OIL AND NATURAL GAS LIQUIDS NATURAL GAS AVAILABLE FOR SALE (Millions of barrels of oil equivalent) (Thousands of barrels a day) (Millions of cubic feet a day) 1,000 2,500 5,000

800 2,000 4,000

600 1,500 3,000

400 1,000 2,000

200 500 1,000

1996 1997 1998 1996 1997 1998 1996 1997 1998 United States International United States International 12 TEXACO 1998 ANNUAL REPORT

To Our Stockholders:

1998 was the toughest time we have faced in my 33 years with the Company. Despite an excellent operational performance, our financial results were sharply lower than the out- standing results we turned in for 1997.

Although our financial results may not show it, we did what we said we would do in 1998.We achieved our key operational goals by increasing production 9% over 1997, replacing 166% of our production and making a significant exploration discovery in Nigeria.Also, our new joint ventures with Shell and Saudi Refining, Inc. in the U.S. downstream are up and running. However, all of this was not enough to offset the disappointing impact that low commodity prices had on the price of our stock.

A difficult price environment, however, is an excuse we simply don’t accept. Our goal is to outperform our competitors in creating shareholder value, whatever the price environment.

That is why we made tough choices in 1998, and why we are continuing to take disciplined actions to keep the Company strong and healthy in this challenging environment.And when the market recovers, we will be ready to quickly seize opportunities and make the best use of the technologies and streamlined structure that are revitalizing our business.

In this letter, I first want to discuss the state of the energy business.Then I’ll describe the actions that we are taking to invigorate our operations and grow shareholder value.

The Competitive Landscape Has Changed Oil prices for West Texas Intermediate fell from an average of $20.61/barrel in 1997 to $14.39/barrel in 1998.This $6.22 drop in price represented a reduction of almost $1 billion in 1998 earnings to Texaco, and similar declines for most of our competitors.

The primary reason for the stunning drop in oil prices has to do with supply and demand. In 1997,Asia suffered a rapid and unexpected financial crisis, which in turn spawned a pre- cipitous worldwide economic slowdown. Demand for oil and other energy products is highly sensitive to increases in Gross Domestic Product, so that when economies almost stalled around the world, the demand growth for our commodities also slowed sharply.

A stubborn expansion of supply in early 1998 exacerbated this market weakness. Even though OPEC and a few non-OPEC producers moved to stem the growing surplus by mid-1998, these actions were “too little, too late.” This, along with other factors such as a mild winter in the Northern Hemisphere, has caused inventories of crude and refined products to remain high.

We already see the beginnings of an economic recovery in parts of Asia.Also, capital expen- diture cutbacks by almost all oil and gas companies have already resulted in a reduction of 13

crude oil and natural gas production. OPEC may well react to the oversupply by reducing its output, which would also help stabilize prices. Looking beyond the current economic down- turn, we see signs of a cyclical upturn in 2000.

Frankly, however, even with these encouraging signs, oil prices may not readily return to their historical price range. Prices may have also adjusted to another structural factor: the efficiencies created by new technology.

Technologies such as horizontal drilling,“smart” downhole technologies, 3-D seismic visual- ization, and floating ship producing operations have enabled the industry to locate, drill, produce and transport oil and gas much more efficiently than ever before.As an industry, we have reduced the cost and the cycle times required to bring hydrocarbons to market. Technology has not only made it easier to do our business; it may have changed the eco- nomics of our business.

Mergers Among Our Competitors Some of our competitors have reacted to the new competitive marketplace by consoli- dating. BP and Amoco announced they were joining forces in August, Exxon/Mobil and Total/Petrofina last December.At Texaco, we are constantly evaluating the changed com- petitive landscape and assessing what actions will create the most value for our share- holders, including mergers and acquisitions. We have also taken steps to improve our competitive position. Let me describe two of them:

First, we are already achieving the benefits of mergers in one of our most significant busi- nesses, the U.S. refining, marketing, trading and transportation and lubricants operations — and we did it two years before our competitors.The U.S. remains a strong market for gaso- line, having grown a surprising 2.4% last year.

Our alliances with Shell and Saudi Refining, Inc., announced in 1997, are the largest down- stream enterprises in the United States, with about $16.8 billion of assets, accounting for some 15% of the nation’s market share.

We expect that our alliances will produce, proportionately, a larger magnitude of cost savings than those announced by our merging competitors…and that they will produce them quicker.Together with our partners, we have already completed the complicated job of weaving our organizations together. Our competitors have yet to face this difficult and time-consuming task.

We will accomplish similar efficiencies on a smaller scale with our worldwide Fuel and Marine Marketing venture with Chevron.We are convinced that, with selective joint ventures such as these, we can achieve the same benefits and cost savings as mergers, but tar- geted to specific business needs. 14

Second, in the upstream, we are well positioned with our high-potential set of opportuni- ties, notably in West Africa, Kazakhstan and the Gulf of Mexico. One of the areas we set about improving over the last two years was our exploration program, and I am pleased to report that we have achieved considerable success.We are especially encouraged by our recent Nigerian discovery.

How to Grow Value

FIRST, ASSURE PRODUCTION IS PROFITABLE The changed marketplace has compelled us to modify the strategies we developed when oil prices were higher. For example, we will keep our production volumes to about the same level they were in 1998 and concentrate on maximizing per-barrel profits by driving down costs.

SECOND, FIND EFFICIENCIES We have identified over $450 million in annual pre-tax cost savings in 1999 from expense reductions at various businesses including synergies in the U.S. downstream ventures and restructuring in Caltex and the Exploration and Production organization.As a result of these efforts, we made the hard decision to eliminate about 3,000 jobs. In 1999, we are attempting to accelerate $200 million in cost savings that were planned for 2000.We hope to achieve a total of $650 million of efficiencies for 1999 and every year thereafter.

However, we aren’t just cutting costs; we are changing the way we do business. For example, as part of the upstream restructuring that we expect will save $100 million this year and $200 million annually in 2000 and beyond, we analyzed the “value creation chain” for this business.This is the life cycle of oil and gas reserves that moves from discovery through commercialization and production and finally to sale or disposal.Three of our most tal- ented and experienced corporate officers have been given primary responsibility for each important phase of the cycle so that we can realize greater value during every stage of asset life.

In another example, we and our partner Chevron have restructured and flattened the operations in our Caltex joint venture, positioning it to outperform our competitors in the promising Asia-Pacific growth area. Over the next five years, this area will add nearly as many people as now reside in the entire United States.We are moving the heart of this operation to Singapore, so that the senior management team will have a closer “line of sight” with the business units, which should speed cycle time and improve decision-making. In addition to reducing $50 million of Caltex expense in 1999, it will also help us develop closer relationships within countries and with our customers.When the Asian economies rebound, Caltex will be revitalized and positioned to be the pre-eminent competitor in this theatre of operations.

THIRD, SEIZE OPPORTUNITIES IN THE DOWNSTREAM BUSINESSES In this low crude oil price environment, we will focus on the more profitable refining and marketing businesses around the world. I have already discussed our ambitions in the growing U.S. marketplace and in the Asia-Pacific areas. TEXACO 1998 ANNUAL REPORT 15

In the last two years, we have achieved a $160 million turnaround in our European refining and marketing operations through an aggressive strategy of profitable growth, focused expense containment and customer satisfaction. Our Latin American and Caribbean opera- tions continued their outstanding performance last year, earning in excess of $300 million. We will continue our drive towards revenue growth and profitability in both of these areas during 1999.

FOURTH, JUDICIOUS CAPITAL EXPENDITURES AND CASH CONTROL We reduced our capital budgets for 1998 and 1999.As we proceed through the year we will test our capital expenditures to ensure that we find the optimal balance between conserv- ing cash and funding projects with the greatest opportunities to provide higher returns and grow stockholder value.

At the end of 1998 our debt to total debt and equity ratio was 36.8%, well within our target range of 35–40%. Maintaining our rates in this range gives us the financial flexibility to use our debt capacity together with our stock to participate in acquisition opportunities, fund our capital requirements and pay a competitive dividend.

FIFTH, ENGAGE THE ORGANIZATION Our compensation programs are designed to align rewards for employees at all levels with stockholder value. For example, most employees participate in a bonus program linked to our competitive positioning in earnings growth and total return to stockholders. If we rank lower than fifth compared to our peers, there are no payouts under the program.

We have linked compensation to performance to a much greater degree for senior exec- utives and officers. In 1999, for example, because we are committed to aligning our compensation with the fortunes of our stockholders, top managers at Texaco will forego salary increases.

Our Workforce: The Energy Within Texaco One of Texaco’s distinctive advantages is our workforce, which is characterized by dedi- cated, energetic people who consistently deliver outstanding results. I thank every one of them for their hard work and their astonishing spirit and drive, especially in this extremely difficult time.

We are also committed to protecting our employees. In 1998, we renewed our emphasis on safety to ensure that our employees and contractors work in safe environments every day. We also formed a Safety Council to assess our facilities and ensure we are employing the best safety practices in industry.

Similarly, we are performing environmental assessments in several areas, including a base- line of greenhouse gas emissions and audits of our worldwide producing operations, to 16 TEXACO 1998 ANNUAL REPORT

ensure that our practices are consistent with the highest levels of environmental protec- tion and conservation in industry.

We are committed to developing our fine workforce and to developing outstanding leaders. We are developing systematic methods to honestly assess the talents and needs of our employees and help them develop their skills to advance in their careers. In addition, we have developed a comprehensive system for evaluating the leadership skills of all man- agers and supervisors throughout our organization.

Because strong leadership is the single most important way to achieve sustained competi- tive advantage, the nine members of the Executive Council, including me, are all committed to recruit, develop and challenge talented leaders inside and outside of the organization. I have personally taken responsibility for developing up to 125 promising employees work- ing in every area and at all levels of the Company.

We are making progress in our diversity initiatives, despite the tough economic circum- stances in our industry. In 1998, 58% of our hires and 48.6% of our promotions went to highly talented women and minorities.The fresh insights and ideas brought by employees with diverse backgrounds and skills are broadening our already accomplished workforce and helping us to better reflect and understand the marketplace in which we operate.

We are also pleased that we have exceeded our 1998 commitment to spend $176 million with minority and women-owned business enterprises by spending $230 million or 8.3% of our total discretionary expenditures. After just two years we are more than halfway to meeting our five-year goal of spending $1 billion with these firms.

Texaco Foundation: Music, Math and Science We have given our Texaco Foundation a new focus, which is linked to our future workforce needs and the educational needs in the next century. Our Foundation is now guided by two simple beliefs: 1) that early childhood learning is critical to educational achievement and 2) the workforce of the next century must include a diverse pool of scientists and engineers. Our Foundation is encouraging schoolchildren’s natural curiosity about science through interactive,“hands on” learning programs.

We are especially interested in the role that music plays in improving children’s educational achievement, particularly in math and science.Texaco has a special understanding of the power of music, due to our decades-long affiliation with the Metropolitan Opera. Some promising research points to a link between early music education and the reasoning skills essential for the successful study of mathematics and science.To advance the under- standing in this area, we are funding school programs for very young children that explore the link between music education and math and science. 17

We are hopeful that through these programs, we can help to develop the mathematicians, physicists, astronomers, environmental scientists, petroleum engineers and geologists for the 21st century.

* * *

We are fortunate to have added two outstanding new directors to our Board,A. Charles Baillie and Charles R. Shoemate.Their leadership positions in the fields of international banking and consumer products will be a great complement to our Board.

We would like to say a grateful farewell to Directors Willard C. Butcher and Dr. John Brademas, who are retiring from our Board after many years of distinguished service.We thank them for their dedication, their exceptional contributions and unfailing encouragement.

And finally, as always, we extend our thanks to our stockholders and customers for your continuing support, especially during these challenging times.We are confident that as the world economy gains momentum — and it will — your Company will be poised to ener- getically seize the opportunities.

PETER I. BIJUR Chairman of the Board and Chief Executive Officer February 25, 1999 18

Texaco At A Glance

Operating in more than 150 countries,Texaco and its affiliates explore for, find, produce and sell crude oil, natural gas liquids (NGLs) and natural gas; manufac- ture and market high-quality fuels and lubricant products; operate trading, transportation and distribution facilities and produce electricity or alternate forms of energy for power and manufacturing.

Strengths 1998 Performance Strategies Strong balance sheet.Commitment to Weak demand and oversupply caused Develop and nurture growth businesses ensure long-term success by growing earnings to drop sharply: income by dedicating appropriate capital and profitable production through applica- before special items was $894 million. human resources to them. Either fix tion of leading-edge technology. Fiscal Despite low-price environment, pro- under-performing businesses or sell discipline to operate effectively in duction and refined product sales them to free up capital. Achieve opera- low-price environment. Dedicated increased. tional excellence in all areas of our workforce. More than 60 years of business. Develop a world-class, diverse alliance management. workforce, with explicit leadership development at all levels. Enhance Texaco’s image, reputation and brand by everything we do.

Exploration and Production

We seek, find and produce crude oil, NGLs and natural gas from a global port- folio of fields. Our exploration program is concentrated in the deepwater Gulf of Mexico,West Africa and Latin America, while our core production areas extend to other areas of the U.S., the North Sea, the Middle East and the Pacific Rim.

Strengths 1998 Performance Strategies Strong commitment to fast-tracking We restructured our worldwide Invest in growth through balanced production from new fields, while upstream operations to reduce costs program of acquisitions and discovered reducing lifting costs and finding and and generate long-term opportunities. reserve opportunities, and exploration development costs. Focused exploration We increased production by 9%. in core areas. Leverage technological program to strengthen acreage position We replaced 166% of our worldwide leadership to drive down lifting costs. in core areas while exiting properties production while cutting finding and that no longer fit asset portfolio. development costs by 9%. We out- Effective allocation of capital and appli- ranked the industry in production cation of leading-edge technologies. growth. We made potentially signifi- cant discoveries in Dolphin Deep and Starfish fields offshore Trinidad and Block 216 offshore Nigeria. TEXACO 1998 ANNUAL REPORT 19

Marketing, Manufacturing and Distribution

Texaco and its affiliates own or have interests in 28 refineries worldwide. With our affiliates and joint-venture companies, we market automotive fuels through some 38,000 branded retail facilities worldwide. Through our global businesses, we manufacture and sell lubricants, coolants, marine and aviation fuel, and natural gas.

Strengths 1998 Performance Strategies Worldwide, we are gaining a platform Completed U.S. downstream joint Our global approach is to grow market for growth through new alliances — ventures. Increased product sales in the share, cut costs and fix or sell underper- such as our U.S. joint ventures with U.S., a strong market turnaround in forming businesses. For example: in Shell and Saudi Refining, Inc., which Europe, robust growth in Latin America the U.S., our alliances will capture created the number-one U.S. marketer and the Caribbean, growth of global synergies while serving as a platform — and restructuring businesses such as lubricants and coolants and organiza- for growth. And Caltex will achieve our affiliate, Caltex. We continue to tional efficiencies. Nevertheless, cost savings through a restructuring, maintain a strong presence in Brazil downstream earnings were slightly which includes a headquarters move and elsewhere in Latin America and lower, largely due to weak margins to Singapore. the Caribbean. and significant refinery downtime in the U.S. as well as currency losses in the Caltex region.

Global Gas and Power

Texaco Global Gas & Power’s expertise in power generation and gasification technology complements our natural gas activities worldwide, and frequently enhances our producing and manufacturing operations. With our affiliates and partners, we own, operate and are developing or licensing technology for plants totaling more than 8,200 megawatts of electrical generating capacity.

Strengths 1998 Performance Strategies We are strategically positioned to pur- Even during difficult economic times in We will leverage our strengths in sue power generation opportunities in Asia, a Texaco-led partnership closed power and gasification technology areas such as Asia, in the Americas and project financing on a 700-megawatt to pursue power generation opportuni- Europe, which have strong demand for power plant in Thailand. We are also ties where Texaco has a presence, electricity. Our gasification technology participating in a joint venture to own where we understand the risk/reward is unequaled: Texaco-licensed projects and operate a gasification plant in tradeoffs and where governments currently represent 55% of the total Singapore, which will supply industrial support restructuring and privatization. worldwide market. gases to the chemical industry. Four additional power plants are under devel- opment in Italy, the Philippines and Indonesia. Major World Operations In the U.K. North Sea, we increased daily production by 38%, growing from 112,000 BOE in 1997 to 155,000 BOE in 1998.

Motiva At A Glance

47 product terminals (owns or

has interests in)

Approximately 14,200 branded

outlets in all or part of 26 states

Estimated 15.5% market share in joint venture area

Equilon At A Glance

66 crude oil and product termi-

nals (owns or has interests in)

Approximately 9,400 branded

outlets in all or part of 32 states

Estimated 14.3% market share in joint venture area

Brazil’s population

is 163 million people and growing. We have about 3,200 service stations — and a 13% retail market share there.

Major Areas of Operations: Upstream Major Areas of Operations: Downstream Texaco’s Exploration and Production Texaco Marketing Equilon Marketing Caltex Marketing Equilon Refineries

Texaco Headquarters Caltex Refineries Motiva Marketing Caltex Headquarters Motiva Refineries TEXACO 1998 ANNUAL REPORT 21

Our affiliate,Caltex,

operates in Asia, the Pacific Rim, eastern and southern Africa, and the Middle East with about 8,000 retail outlets.

Worldwide Businesses Vital Statistics Aviation Total reserves: nearly 4.7 billion barrels of oil equivalent (BOE) Lubricants/Additives/Coolants Total production: 1,301 thousands of BOE a day Marine Fuels/Lubricants Refinery input: 1,530 thousands of barrels a day Exploration and Production Worldwide branded service stations: about 38,000 Refined product sales: 2,888 thousands of barrels a day 22

Glossary of Terms

API GRAVITY HEAVY OIL PETROLEUM COKE A measurement of the gravity (weight per A category of crude oil characterized by rela- Solid carbon or coke retained as a residue in unit volume) of crude oil and other liquid tively high viscosity, a higher carbon-to- tar stills after high-temperature distillation. hydrocarbons by a system recommended by hydrogen ratio, and heavier specific gravities the American Petroleum Institute (API). (weights). In the refining process, heavy crude PRODUCED WATER The measuring scale is calibrated in terms of oil generally yields more “heavy” products Water that is produced from a well along “API degrees.” The lower the API gravity, such as asphalt. with oil and gas. the heavier the oil. The higher the API grav- ity, the lighter the oil. HORIZONTAL DRILLING REFINED PRODUCTS A technique in which the drill bit is turned to The marketable processed output of a petro- BARRELS OF OIL EQUIVALENT (BOE) move horizontally through a productive reser- leum refinery. Examples include naphtha, The volume of natural gas that when burned voir, increasing data about the reservoir and gasoline, kerosene, heating oil, diesel, lubri- produces the same amount of heat as a barrel guiding the placement of wells to optimize cant base oils and asphalt. of oil (6,000 cubic feet of gas equals one bar- oil recovery. rel of oil). REFINING MARGIN HYDROCARBONS Similar to gross margin, refining margin rep- COGENERATION Compounds containing hydrogen and carbon resents the composite value of all products A process that harnesses a single fuel such as atoms that may be in solid, liquid or gaseous produced by the refinery minus the cost of natural gas to produce two forms of energy: form, and that form the basis of all petroleum crude. To get the net margin, subtract the electricity and steam or dry heat. products. overhead and manufacturing costs from the gross margin. COMPLIANT TOWER LEASE OPERATING EXPENSES The upper portion of the support pilings of an Production expenses and cost of sales excluding RESERVES oil rig, which is designed to flex with the forces exploration expenses, depreciation, depletion, An economically recoverable quantity of of waves, wind and ocean current and is there- amortization and dry hole expenses. crude oil and gas that has not yet been pro- fore especially suited for deepwater projects. duced from reservoirs. LIGHT OIL DELINEATION WELL A category of crude oil characterized by RESERVOIR A well drilled in an unproven area adjacent to relatively low viscosity, a lower carbon-to- A porous, permeable, sedimentary rock for- a proven well to determine the extent of the hydrogen ratio, and lower specific gravities mation containing oil and/or natural gas reservoir; also referred to as a “stepout” well. (weights). In the refining process, light enclosed or surrounded by layers of less per- crude oil generally yields more “light” prod- meable or impervious rock. DOWNHOLE ucts such as gasoline. A term used in exploration and production to STEAMFLOOD TECHNOLOGY describe tools, equipment and instruments LIQUEFIED NATURAL GAS (LNG) One method of enhanced recovery in which used in the well bore. Also, it refers to condi- Gas, mainly methane, that has been liquefied steam is introduced into the reservoir through tions or techniques applying to the well bore. in a refrigeration and pressure process to facil- an injector well, providing heat and pressure itate storage and transportation. to push heavy oil toward the surrounding pro- DOWNSTREAM ducing wells. All activities associated with the refining, LIQUEFIED PETROLEUM GAS (LPG) marketing and transportation of petroleum A mixture of butane, propane and other light SYNTHETIC GAS (SYNGAS) products. hydrocarbons. At normal temperature it is a A synthetic fuel created from hydrocarbon gas, but it can be cooled or subjected to pres- feedstocks, which may be used as a building ENHANCED RECOVERY sure to facilitate storage and transportation. block to produce electricity, industrial chem- Various technologies for increasing or prolong- icals, gases and other petroleum products. ing the productivity of oil and natural MIDSTREAM gas fields. Common methods include water- All activities associated with storage and THREE-DIMENSIONAL SEISMIC IMAGING (3D) flooding and steamflooding. transport of crude oil and natural gas (before A technology that involves bouncing processing) via ship, rail, truck or pipeline. sound waves off formations to create three- GASIFICATION dimensional images, which enable oil An environmentally superior technology for NATURAL GAS companies to find likely sites of oil and gas. converting a wide variety of hydrocarbon fuels A naturally occurring mixture of hydrocar- (coal, heavy oil, petroleum coke, natural gas bons found in porous sedimentary rocks in the UPSTREAM and wastes) into clean synthetic gas, or “syn- earth’s crust, usually in association with All activities associated with the exploration gas,” which is used to produce electricity, petroleum deposits. and production of crude oil and natural gas. industrial chemicals and gases as well as fuels and fertilizers. NATURAL GAS LIQUIDS (NGLs) WTI A mixed stream of ethane, propane, butane An abbreviation for West Texas Intermediate. and pentanes that is split into individual WTI is a specific grade of crude oil that is a components and either sold or used as feed- benchmark commodity of the U.S. oil industry. stocks for refineries and chemical plants. TEXACO 1998 ANNUAL REPORT 23

Financial Table of Contents

Management’s Discussion and Analysis 24 Description of Significant Accounting Policies 41 Statement of Consolidated Income 43 Consolidated Balance Sheet 44 Statement of Consolidated Cash Flows 45 Statement of Consolidated Stockholders’ Equity 46 Statement of Consolidated Nonowner Changes in Equity 48 Notes to Consolidated Financial Statements Note 1 Segment Information 49 Note 2 Adoption of New Accounting Standards 51 Note 3 Income Per Common Share 51 Note 4 Acquisition of Monterey Resources 52 Note 5 Inventories 52 Note 6 Investments and Advances 52 Note 7 Properties, Plant and Equipment 55 Note 8 Foreign Currency 55 Note 9 Taxes 56 Note 10 Short-Term Debt, Long-Term Debt, Capital Lease Obligations and Related Derivatives 57 Note 11 Lease Commitments and Rental Expense 59 Note 12 Employee Benefit Plans 60 Note 13 Stock Incentive Plan 63 Note 14 Preferred Stock and Rights 64 Note 15 Financial Instruments 65 Note 16 Other Financial Information,Commitments and Contingencies 67 Report of Management 69 Report of Independent Public Accountants 69 Supplemental Oil and Gas Information 70 Supplemental Market Risk Disclosures 76 Selected Financial Data Selected Quarterly Financial Data 77 Five-Year Comparison of Selected Financial Data 78 Investor Information 81 24 TEXACO 1998 ANNUAL REPORT

Management’s Discussion and Analysis

Introduction In 1996, the Securities and Exchange Commission (SEC) In the Analysis of Income by Operating Segments, we show issued plain English guidelines to improve shareholder and discuss our operating segments: Exploration and communications. In 1997, we were the first major energy Production (Upstream), Manufacturing, Marketing and company to begin writing our Management’s Discussion Distribution (Downstream) and Global Gas Marketing. and Analysis (MD&A) in plain English. This year we con- We also show and discuss Other Business Units and our tinue to expand the use of plain English. Corporate/Non-operating results. Our discussion focuses on major business factors affecting our results.

We were the first major energy In the Other Items section, we discuss other important company to write our MD&A items: in plain English. ➤ Liquidity and Capital Resources: Our program to man- age cash, working capital and debt and other actions that provide us financial flexibility In the MD&A, we explain the operating results and general ➤ Capital and Exploratory Expenditures: Our program financial condition of our company. The MD&A begins with to invest in our business, especially in projects aimed at a table of financial highlights that provides a financial pic- future growth ture of the company. The remainder of our MD&A consists of four main topics: Industry Review, Results of Operations, ➤ Environmental Matters: A discussion about our expendi- Analysis of Income by Operating Segments and Other Items. tures relating to protection of the environment ➤ New Accounting Standards: A description of new In the Industry Review, we discuss the economic factors accounting standards to be adopted that affected our industry in 1998. We also provide our near-term outlook for the industry. ➤ Euro Conversion: The status of our program to convert to the new euro currency In the Results of Operations, we compare and describe ➤ Year 2000: The status of our program to identify and changes in consolidated revenues, costs, expenses and correct our computers, software and related technologies to income taxes. Summary schedules, showing results before be year 2000 compliant and after special items, complete this section. Special items are significant events that affect our results but are outside the scope of normal current-year operations. Our discussions in the MD&A and other sections of this Annual Report contain forward-looking statements that are based upon our best estimate of the trends we know about or anticipate. Actual results may be different from our esti- mates. We have described in our 1998 Annual Report on Form 10-K the factors that could change these forward- looking statements. TEXACO 1998 ANNUAL REPORT 25

Financial Highlights

(Millions of dollars, except per share and ratio data) 1998 1997 1996 Revenues $ 31,707 $ 46,667 $ 45,500 Income before special items and cumulative effect of accounting change $ 894 $ 1,894 $ 1,665 Special items (291) 770 353 Cumulative effect of accounting change (25) — — Net income $ 578 $ 2,664 $ 2,018 Diluted income per common share (dollars) Income before special items and cumulative effect of accounting change $ 1.59 $ 3.45 $ 3.03 Special items (.55) 1.42 .65 Cumulative effect of accounting change (.05) — — Net income $ .99 $ 4.87 $ 3.68 Cash dividends per common share (dollars) $ 1.80 $ 1.75 $ 1.65 Total assets $ 28,570 $ 29,600 $ 26,963 Total debt $ 7,291 $ 6,392 $ 5,590 Stockholders’ equity $ 11,833 $ 12,766 $ 10,372 Current ratio 1.07 1.07 1.24 Return on average stockholders’ equity* 4.9% 23.5% 20.4% Return on average capital employed before special items* 6.5% 13.0% 12.8% Return on average capital employed* 5.0% 17.3% 14.9% Total debt to total borrowed and invested capital 36.8% 32.3% 33.6%

*Returns for 1998 exclude the cumulative effect of accounting change (see Note 2 to the financial statements).

Industry Review Introduction second-largest economy, experienced its worst downturn in Crude oil prices have a major effect on our financial per- the post-war period, caused by a collapse in consumer and formance. The price of crude oil is determined in the investor confidence and severe banking problems. Several of international market by the often complex interaction of developing Asia’s key economies, including Indonesia, worldwide petroleum demand and supply. In 1998, crude Hong Kong, Korea, Malaysia, Singapore and Thailand also oil prices were driven down by several factors which influ- plunged into recession, crippled by a regional financial crisis enced demand and supply. These included economic which began in July 1997. activity, weather patterns and actions of the Organization The financial turbulence eventually spread to Russia and of Petroleum Exporting Countries (OPEC). Latin America. Russia’s economy registered a steep decline. In Latin America, the heightened financial uncertainty ulti- mately pushed the large Brazilian economy into recession, For 1998, WTI crude oil prices aver- and slowed growth in other Latin American countries. aged $14.39 per barrel, or about Moreover, weak commodity prices — attributable in part to 30% below the 1997 average. the slowdown in Asia — curtailed economic growth in other areas, particularly the oil producing countries of the Middle East and Africa. In sharp contrast to the areas experiencing economic Review of 1998 recession or stagnation, the U.S. and Western Europe enjoyed In 1998, the world experienced a severe economic crisis. favorable economic conditions. U.S. growth remained robust Global economic growth averaged a meager 1.6%, signifi- as the economy benefited from lower interest rates, and cantly below the 4% growth recorded in 1997 and 1996. Western Europe showed an improvement because of higher Economic activity varied widely among regions, with consumer spending. many Asian countries hit the hardest. Japan, the world’s 26 TEXACO 1998 ANNUAL REPORT

Economic activity has a major effect on petroleum con- Near-Term Outlook sumption. The deterioration in major portions of the global We have begun to see signs of stabilization in the global economy resulted in a substantial reduction in oil demand economic crisis, prompted by various steps taken by the growth, which increased by only about 400,000 barrels per U.S. and other industrialized countries, including: day (BPD) or 0.5% during 1998. This represents a dramatic ➤ The cutting of interest rates by the U.S. Federal Reserve slowing from the roughly 2 million BPD growth which and other central banks occurred in both 1997 and 1996. Demand in Asia suffered the largest decline, about 500,000 BPD. This was a sig- ➤ An increase in the International Monetary Fund’s loanable nificant development, since growth in Asia had accounted resources by more than $90 billion for about half of the total worldwide increase in recent ➤ A significant financial rescue package for Brazil years. Moreover, warm weather at both the beginning and end of 1998 constrained oil consumption in the U.S. and ➤ Japanese banking reform legislation and implementation Western Europe. of fiscal measures to stimulate the economy Crude oil prices were further weakened by significant increases in petroleum supplies early in 1998. Specifically: Although there are some preliminary indications that the troubled economies of Asia may be bottoming-out, improve- ➤ OPEC countries set new, higher production quotas in ments in the region could be partly offset by slower expan- late 1997 and proceeded to exceed them sions in the U.S., Western Europe and Latin America. In ➤ U.N.-sanctioned crude oil exports from Iraq increased addition, the Russian economy shows no signs of a near- sharply term turnaround. Accordingly, we anticipate only a 1.7% increase in world economic output in 1999. ➤ Production from non-OPEC countries also increased These elements point to a continued weak oil market in 1999. OPEC’s production cuts are due to expire in June, and These actions led to a large increase in worldwide petro- it is unsure if they will be expanded, or even extended. In leum inventories. By mid-1998, OPEC, Mexico and a few the absence of additional large-volume production reduc- other non-OPEC producers agreed to reduce their combined tions, high worldwide petroleum inventories are likely to oil production by about 3 million BPD. Yet, in the face of constrain any significant recovery in oil prices through at lower demand, this attempt to improve the growing market least mid-1999. imbalance did not prevent the slide in world oil prices. The market price of West Texas Intermediate (WTI) crude oil Results of Operations slipped from an average of about $16.70 per barrel in Revenues January to $11.30 per barrel during December. Our consolidated worldwide revenues were $31.7 billion in 1998, $46.7 billion in 1997 and $45.5 billion in 1996. TEXACO’S U.S. REALIZED CRUDE OIL PRICE PER BARREL (Dollars) Approximately 80% of the decrease in 1998 resulted from the accounting for Equilon, a downstream joint venture in $20 the United States we formed in January 1998. Under $16 accounting rules, the significant revenues of the operations we contributed to this joint venture are no longer included in $12 our consolidated revenues. Revenues, costs and expenses of $8 the joint venture are reported net as “equity in income of affiliates” in our income statement. $4

Sales Revenues — Price/Volume Effects 1996 1997 1998 Our sales revenues decreased in 1998 due to historically low Prices in 1998 fell to historically low levels. commodity prices throughout our global markets. Crude oil, natural gas and refined product prices were all lower. Partly offsetting lower sales revenue due to declining prices In addition to lower worldwide crude oil prices, warmer were higher volumes. We continue to expand our produc- than normal weather and excess capacity caused natural gas tion and sales volumes through successful capital investments prices in the U.S. to decline almost 20%. and focused market expansion. Worldwide production in TEXACO 1998 ANNUAL REPORT 27

1998 increased by 9% following an increase of 6% in 1997. levels that existed at the end of 1998. If in the future we These increases span our global areas of operations includ- change this view, asset impairments may result. ing the United States, the U.K. and the Partitioned Neutral Employee separation costs increased our other expenses Zone. Refined product sales growth included expanded by approximately $133 million. In the fourth quarter of activities in Latin America and Europe. We also expanded 1998, we announced reorganizations for several of our our aviation, marine and other refined product trading operations and began implementing other cost-cutting ini- activities in the U.S., which are handled outside the joint tiatives to reduce costs and improve focus in growth areas. ventures. Natural gas sales also grew as we expanded our As a result, we accrued for employee severance costs. The marketing activities in the United States. principal units affected were our worldwide upstream operations, our North America natural gas operations, our Other Revenues marketing operations in the U.K. and Brazil, our manufac- Other revenues include our equity in the income of affiliates, turing operations in Panama, and our corporate center. income from asset sales and interest income. Results for We expect that the reorganizations and other initiatives will 1998 show a decrease in other revenues. Equity in income of be substantially completed by the end of the first quarter affiliates decreased in 1998, mostly due to a decline in of 1999. For additional information, see Note 12 to the Caltex’ results and special charges recorded by several of our financial statements. affiliates. This decline was partly offset by the inclusion of Special charges in 1997 were $136 million principally for results for Equilon. Income from asset sales was also lower asset write-downs and royalty litigation issues, and $152 mil- in 1998. In 1997 we sold a 15% interest in the U.K. North lion in 1996 for employee separation and litigation matters. Sea Captain field and our upstream interests in Myanmar. Interest expense for 1998 increased due to higher aver- age debt levels after a slight decrease in 1997. Costs and Expenses During 1998 we kept tight control over expenses as we Costs and expenses from operations were $30.5 billion in continued to grow our business. Our success is illustrated 1998, $42.9 billion in 1997 and $42.0 billion in 1996. by the chart below. Similar to the explanation of revenues, the decrease for both costs and expenses for 1998 is largely due to the equity CASH EXPENSES PER BARREL accounting treatment for our joint venture company, Equilon. (Dollars) Excludes operations now in Equilon and special items. The impact of lower prices, which reduced our cost of goods $5 sold, was partly offset by higher purchased volumes. $4 Special items recorded by our subsidiaries increased costs and operating expenses in 1998 by $382 million. Principal $3 charges were for inventory valuation adjustments, asset $2 write-downs and employee separation costs. Inventory valu- ation adjustments to reflect lower market prices for crude $1 oil and refined products increased costs by $99 million. Asset write-downs, which increased depreciation expense 1996 1997 1998 by $150 million, resulted from impairments primarily in Tight controls on expenses led to an 8% reduction per barrel our upstream operations. These and other asset impairments in 1998. that we have recognized since initially applying the provi- sions of SFAS 121 have been driven by specific events, such as the sale of properties or downward revisions in under- ground reserve quantities, not changes in prices used to In 1998, we targeted about $650 calculate future revenues by year. In performing our impair- million in annual pre-tax cost ment reviews of assets not held for sale, we use our best savings through the year 2000. judgment in estimating future cash flows. This includes our outlook of commodity prices based on our view of supply and demand forecasts and other economic indicators. Our present outlook is that prices will recover from their low 28 TEXACO 1998 ANNUAL REPORT

Income Taxes Income (loss) Income tax expense was $98 million in 1998, $663 million (Millions of dollars) 1998 1997 1996 in 1997 and $965 million in 1996. The decrease in 1998 is mostly due to lower income. The year 1997 included a Income before special items $488 million benefit for an IRS settlement. The years 1998 and cumulative effect of and 1996 included benefits of $43 million and $188 mil- accounting change $ 894 $ 1,894 $ 1,665 lion from the sales of interests in a subsidiary. Special items: Inventory valuation Income Summary Schedules adjustments (142) — — The following schedules show results before and after spe- Asset write-downs (93) (41) — cial items and before the cumulative effect of accounting Employee separation costs (80) — (65) change. A full discussion of special items is included in our Caltex reorganization (43) — — Analysis of Income by Operating Segments. U.S. joint venture formation issues (21) — — Gains on major asset sales 20 367 194 Tax benefits on asset sales 43 — 188 Tax and other issues 25 444 36 Total special items (291) 770 353 Income before cumulative effect of accounting change $ 603 $ 2,664 $ 2,018

The following schedule further details our results:

Income (loss)

Before Special Items After Special Items (Millions of dollars) 1998 1997 1996 1998 1997 1996 Exploration and production U.S. $ 381 $ 1,038 $ 1,074 $ 301 $ 990 $ 1,074 International 172 474 466 120 807 493 Total 553 1,512 1,540 421 1,797 1,567 Manufacturing, marketing and distribution U.S. 278 311 236 223 324 210 International 503 524 249 332 508 447 Total 781 835 485 555 832 657 Global gas marketing (35) (43) 34 (18) (43) 34 Total 1,299 2,304 2,059 958 2,586 2,258 Other business units 7 5 10 7 5 10 Corporate/Non-operating (412) (415) (404) (362) 73 (250) Income before cumulative effect of accounting change $ 894 $ 1,894 $ 1,665 $ 603 $ 2,664 $ 2,018

Analysis of Income by Operating Segments Upstream In our upstream business, we explore for, find, produce and ronment and other business factors affected our earnings. sell crude oil, natural gas liquids and natural gas. We will present our U.S. and international results and Our upstream operations were significantly challenged conclude our discussion with some forward-looking com- in 1998, due to lower crude oil and natural gas prices. The ments. The U.S. results include some minor Canadian following discussion will focus on how the low-price envi- operations which were sold in December 1998. TEXACO 1998 ANNUAL REPORT 29

United States Upstream

(Millions of dollars, except as indicated) 1998 1997 1996 Operating income before special items $ 381 $ 1,038 $ 1,074 Special items: Asset write-downs (51) (31) — Employee separation costs (29) — — Gains on major asset sales — 26 — Tax and other issues — (43) — Total special items (80) (48) — Operating income $ 301 $ 990 $ 1,074

Selected Operating Data: Net production Crude oil and NGL (thousands of barrels a day) 433 396 388 Natural gas available for sale (millions of cubic feet a day) 1,679 1,706 1,675 Average realized crude price (dollars per barrel) $ 10.60 $ 17.34 $ 17.93 Average realized natural gas price (dollars per MCF) $ 2.00 $ 2.37 $ 2.19 Exploratory expenses (millions of dollars) $ 257 $ 189 $ 153 Production costs (dollars per barrel) $ 4.07 $ 3.94 $ 3.82 Return on average capital employed before special items 6.0% 21.2% 23.7% Return on average capital employed 4.8% 20.2% 23.7%

WHAT HAPPENED IN THE UNITED STATES? Business Factors PRICES Lower prices in 1998 reduced earnings by $647 mil- U.S. PRODUCTION lion. Our average realized crude oil price decreased 39% (Thousands of barrels of oil equivalent a day) to $10.60 per barrel. This follows a 3% decrease in 1997. 800 Natural Gas In 1998, crude oil prices plummeted to over 20 year lows in Crude Oil the fourth quarter. Our average realized natural gas price 600 decreased 16% in 1998 to $2.00 per MCF. This follows an 8% increase in 1997. 400

200 PRODUCTION Our production increased 5% in 1998. This follows a 2% increase in 1997. The increases are due to the acquisition of heavy oil producer Monterey Resources in 1996 1997 1998 November 1997. We also had new production in the Gulf of Growth of 5% in 1998 due to higher production in California Mexico and higher production from our Kern River field in and the Gulf of Mexico. California. These production increases more than offset nat- ural field declines.

EXPLORATORY EXPENSES We expensed $257 million on exploratory activity in 1998, an increase of 36%. In Our production increased 5% 1998, we continued to focus our exploration efforts in in 1998 while the U.S. industry Texas, Louisiana, California and offshore opportunities in average decreased 3%. the Gulf of Mexico. In 1997, we began spending more money in these areas, contributing to the increase over 1996. 30 TEXACO 1998 ANNUAL REPORT

Other Factors Special Items Our production costs per barrel have increased over the last Results for 1998 included asset write-downs of $51 mil- two years. This increase is due to higher depreciation expenses lion for impaired properties in Louisiana and Canada and and production costs associated with the acquired Monterey $29 million for employee separation costs. properties. However, applying our enhanced oil recovery The employee separation costs result from our announced techniques to the acquired Monterey fields has reduced cash worldwide restructuring which should be completed by lifting costs for these properties by over $1 per barrel. the end of the first quarter of 1999. This restructuring is expected to yield significant annual cost savings.

U.S. PRODUCTION COSTS PER BARREL The impaired Louisiana property represents an unsuccess- (Dollars) ful enhanced recovery project. We determined in the fourth $5 quarter of 1998 that the carrying value of this property exceeded future undiscounted cash flows. Fair value was $4 determined by discounting expected future cash flows. $3 The Canadian properties were impaired following our deci- sion in October 1998 to exit the upstream business in $2 Canada. These properties were written down to their sales $1 price with the sale closing in December 1998. Results for 1997 included a charge of $31 million for asset write-downs, a gain of $26 million from the sale of gas 1996 1997 1998 properties in Canada and a $43 million charge for expense Slight rise due to higher lifting costs of acquired accruals associated with royalty and tax issues. Monterey properties.

International Upstream

(Millions of dollars, except as indicated) 1998 1997 1996 Operating income before special items $ 172 $ 474 $ 466 Special items: Asset write-downs (42) (10) — Employee separation costs (10) — — Gains on major asset sales — 328 — Tax and other issues — 15 27 Total special items (52) 333 27 Operating income $ 120 $ 807 $ 493

Selected Operating Data: Net production Crude oil and NGL (thousands of barrels a day) 497 437 399 Natural gas available for sale (millions of cubic feet a day) 548 471 382 Average realized crude price (dollars per barrel) $ 11.20 $ 17.64 $ 19.55 Average realized natural gas price (dollars per MCF) $ 1.62 $ 1.66 $ 1.79 Exploratory expenses (millions of dollars) $ 204 $ 282 $ 226 Production costs (dollars per barrel) $ 3.74 $ 4.30 $ 4.47 Return on average capital employed before special items 5.5% 17.9% 19.1% Return on average capital employed 3.9% 30.5% 20.2% TEXACO 1998 ANNUAL REPORT 31

WHAT HAPPENED IN THE INTERNATIONAL AREAS? INTERNATIONAL EXPLORATORY EXPENSES Business Factors (Millions of dollars) PRICES Lower prices reduced 1998 earnings by $503 mil- $300 lion. Our average realized crude oil price decreased 37% to $250 $11.20 per barrel. This follows a 10% decrease in 1997. $200 This trend of lower prices began in late 1997 and continued throughout 1998 with prices dropping to over 20 year lows $150 in the fourth quarter. Our average realized natural gas price $100 decreased 2% in 1998 to $1.62 per MCF. This follows a 7% $50 decrease in 1997.

1996 1997 1998 PRODUCTION Our production had double-digit growth Reduction in 1998 spending due to low-price environment. over the last two years. The 1998 increase is attributable to a full year’s production in the U.K. North Sea from the Captain and Erskine fields and new production from the Other Factors Galley field. Combined production from these fields aver- Our production costs per barrel for 1998 were $3.74, down aged 78 thousand barrels-of-oil-equivalent per day in 1998. 13%. As we raised production and maintained control of Production also grew in the Partitioned Neutral Zone and expenses, our costs per barrel decreased. Indonesia. Our natural gas production at the Dolphin field in Operating results included non-cash currency transla- Trinidad and from the Chuchupa field offshore Colombia also tion effects. Years 1998 and 1996 included charges of contributed to our production growth over the last two years. $2 million and $38 million while 1997 included a benefit of $21 million. These effects are derived from our British pound deferred income tax liability. When the pound Our 1998 production increased strengthens against the U.S. dollar, we recognize a charge 14% following an 11% increase and when the pound weakens we experience a benefit. in 1997. INTERNATIONAL PRODUCTION COSTS PER BARREL (Dollars) $5

INTERNATIONAL PRODUCTION (Thousands of barrels of oil equivalent a day) $4 600 Natural Gas $3 Crude Oil 500 $2 400 $1 300 200 1996 1997 1998 100 Lower lifting costs per barrel through operating efficiencies and increased production. 1996 1997 1998 Production grew by 14% in 1998 due to continuing development in the North Sea, Indonesia and the Middle East. Special Items Results for 1998 included a write-down of $42 million for the impairment of our investment in the Strathspey field EXPLORATORY EXPENSES We expensed $204 million on in the U.K. North Sea and employee separation costs of exploration activity in 1998, a decrease of 28%. During the $10 million from an announced restructuring which is last half of 1998 we slowed activities in the Far East. expected to yield annual cost savings. However, we continued our initiatives to increase future The Strathspey impairment was caused by a downward production as we focused on new prospects in the U.K. revision in the fourth quarter of 1998 of the estimated North Sea and West Africa. volume of the field’s proved reserves. Fair value was deter- mined by discounting expected future cash flows. 32 TEXACO 1998 ANNUAL REPORT

Results for 1997 included a $10 million charge for asset Downstream write-downs and gains on asset sales of $328 million. These In our downstream business, we refine, transport and sell sales included a 15% interest in the Captain field in the U.K. crude oil and products, such as gasoline, fuel oil and lubricants. and investments in an Australian pipeline system and the com- Our U.S. downstream includes operations in the pany’s Myanmar operations. Also, 1997 included a $15 million Equilon area and the Motiva area. The Equilon area prior period tax benefit. Results for 1996 included a non- includes western and midwestern refining and marketing cash gain of $27 million for a Danish deferred tax benefit. operations, and nationwide trading, transportation and lubricants activities. Our 1998 results in this area are our LOOKING FORWARD IN THE WORLDWIDE UPSTREAM share of the earnings of our joint venture with Shell, We will continue to cost-effectively explore for, develop and named Equilon, which began operations on January 1, produce crude oil and natural gas reserves. Our areas of 1998. We have a 44% interest in Equilon. Results for 1997 focus include: and 1996 are for our subsidiary operations in this same area. The Motiva area includes eastern and Gulf Coast ➤ The Gulf of Mexico where we hold a significant inven- refining and marketing operations. Our 1998 results are, tory of valuable exploration and development acreage for the last half of the year, our share of the earnings of our ➤ Areas rich in heavy oil reserves, where we will apply our joint venture with Shell and Saudi Refining, Inc., named world class enhanced oil recovery techniques Motiva, which began operations on July 1, 1998. We have a 32.5% interest in Motiva. Results for the first half of ➤ In the U.K. North Sea, where several fields are slated to 1998 and the years 1997 and 1996 are for our share of our phase in production in the years 1999 – 2001 joint venture with Saudi Refining, Inc., named Star. We ➤ In Kazakhstan, where we have a 20% interest in the had a 50% interest in Star. Karachaganak oil and gas field Internationally, our downstream operations are reported separately as Latin America and West Africa and Europe. ➤ In West Africa, where we recently announced a major oil We also have a 50% joint venture with Chevron named discovery offshore Nigeria, and in Latin America Caltex which operates in Africa, Asia, Australia, the Middle East and New Zealand. In the U.S. and international operations, we also have We expect $200 million in annual other businesses, which include aviation and marine prod- pre-tax cost savings from our uct sales and other refined product trading activity. recent upstream restructuring. We will present our U.S. and international results and conclude our discussion with some forward-looking comments.

United States Downstream

(Millions of dollars, except as indicated) 1998 1997 1996 Operating income before special items $ 278 $ 311 $ 236 Special items: Inventory valuation adjustments (34) — — Employee separation costs — — (1) U.S. joint venture formation issues (21) — — Gains (losses) on major asset sales — 13 (25) Total special items (55) 13 (26) Operating income $ 223 $ 324 $ 210

Selected Operating Data: Refinery input (thousands of barrels a day) 698 747 724 Refined product sales (thousands of barrels a day) 1,203 1,022 1,036 Return on average capital employed before special items 9.6% 9.8% 7.4% Return on average capital employed 7.7% 10.2% 6.6% TEXACO 1998 ANNUAL REPORT 33

WHAT HAPPENED IN THE UNITED STATES? Equilon Area These operations contributed 79% of our 1998 branded gasoline sales of 2%. The year 1997 benefited from operating income before special items. The 1998 earnings improved Gulf Coast refining margins while 1996 earn- were flat when compared with 1997. Strong transportation ings were adversely affected by refinery disruptions that and lubricants earnings as well as cost and expense reduc- lowered yields. tions were offset by the effects of significant downtime at certain refineries, lower margins and interest expense. Special Items Results for 1998 included a charge for inven- Refined product sales volumes increased. This includes a tory valuation adjustments of $34 million to reflect lower 4% growth in Texaco branded gasoline sales. We achieved market prices for crude oil and refined products and a net higher results for 1997 from improved refining margins, charge of $21 million for U.S. alliance formation issues. better run-rates at our refineries and effective cost cutting. This net charge includes charges of $52 million for In 1996, increased crude oil costs late in the year sent mar- employee separations and $45 million for asset write-downs gins downward from a second quarter peak. of closed facilities and surplus equipment and other expenses. Also included in other net charges were gains of Motiva Area These operations contributed 21% of our 1998 $76 million for the Federal Trade Commission-mandated operating income before special items. The 1998 earnings sales of the Anacortes refinery and Plantation pipeline. were lower due to refinery downtime coupled with lower Results for 1997 included a gain of $13 million from the refining margins. Refined product sales were higher as a sale of our credit card business. Results for 1996 included result of our new joint venture and an increase in Texaco charges of $26 million primarily related to the sale of a propylene oxide/methyl tertiary butyl ether (PO/MTBE) manufacturing site in Texas.

International Downstream

(Millions of dollars, except as indicated) 1998 1997 1996 Operating income before special items $ 503 $ 524 $ 249 Special items: Inventory valuation adjustments (108) — — Employee separation costs (20) — (21) Caltex reorganization (43) — — Gains on major asset sales — — 219 Tax and other issues — (16) — Total special items (171) (16) 198 Operating income $ 332 $ 508 $ 447

Selected Operating Data: Refinery input (thousands of barrels a day) 832 804 762 Refined product sales (thousands of barrels a day) 1,685 1,563 1,552 Return on average capital employed before special items 8.1% 8.9% 4.5% Return on average capital employed 5.3% 8.7% 8.0%

WHAT HAPPENED IN THE INTERNATIONAL AREAS? Latin America and West Africa Our operations in Latin Europe Our European operations contributed 25% of 1998 America and West Africa contributed 63% of 1998 operat- operating income before special items. Earnings increased ing income before special items. Refined product sales significantly from improved refining and marketing volumes increased due to service station acquisitions and margins. Additionally, we grew our refined product sales the expansion of our industrial customer base. We also real- volumes by increasing retail outlets and obtaining new ized improved refinery operations in Panama. In 1997, commercial business. In 1997, earnings increased as general earnings increased due to higher refining margins and a industry conditions improved from the historically low growth in product sales volumes. levels experienced in 1996. 34 TEXACO 1998 ANNUAL REPORT

Results for 1998 and 1996 included non-cash currency and Brazil, and a charge of $43 million for a reorganization charges of $3 million and $20 million related to deferred program in Caltex. income taxes that are denominated in British pounds while The Caltex charge results from their decision to struc- 1997 had a $7 million benefit. ture their organization along functional lines and to reduce costs by establishing a shared service center in the Caltex Our Caltex operations contributed 9% of 1998 oper- Philippines. In implementing this change, Caltex will ating income before special items. In 1998, our share of relocate its headquarters from Dallas to Singapore. About Caltex’ results was $163 million lower. The dramatic earn- $35 million of the charge relates to severance and other ings decline was due to currency-related losses in 1998 retirement benefits for about 200 employees not relocating, versus gains in 1997. The year-to-year earnings decline due write-downs of surplus furniture and equipment and to currency effects was $204 million. Excluding currency other costs. The balance of the charge is for severance costs effects, Caltex’ results in 1998 improved as both margins in other affected areas and amounts spent in relocating and volumes were higher. This improvement was accom- employees to the new shared service center. plished in spite of the economic downturn experienced by Results for 1997 included a charge of $16 million pri- many Asian economies. Our share of Caltex’ results in 1997, marily for a European deferred tax adjustment. Results excluding currency-related gains of $101 million, was basi- for 1996 included a charge for employee separations of cally unchanged from 1996. Strong operational results in $21 million and a gain of $219 million related to the sale the first nine months of 1997 eroded in the fourth quarter of Caltex’ interest in Nippon Petroleum Refining due to the economic crisis in Southeast Asia. Company, Limited. In the Caltex area, most of our operations have a net lia- bility exposure which creates currency losses when foreign LOOKING FORWARD IN THE WORLDWIDE DOWNSTREAM currencies strengthen against the U.S. dollar and currency We anticipate that our joint ventures with Shell and Saudi gains when these currencies weaken against the U.S. dollar. Refining, Inc. will continue to lower costs and capture Effective October 1, 1997, Caltex changed the functional synergies. Our share of these annual pre-tax cost reductions currency used to account for operations in Korea and Japan is expected to be over $300 million. We will continue to to the U.S. dollar. expand in Latin America. In addition, our share of the annual pre-tax cost savings from the Caltex reorganization INTERNATIONAL REFINERY INPUT is expected to be $25 million. (Thousands of barrels a day) 900 LAWA Global Gas Marketing Caltex 750 Europe (Millions of dollars, except as indicated) 1998 1997 1996 600 Operating income (loss) 450 before special items $ (35) $ (43) $ 34 300 Special items: Employee separation costs (3) — — 150 Gain on major asset sales 20 — — Total special items 17 — — 1996 1997 1998 Operating income (loss) $ (18) $ (43) $ 34 Texaco’s refinery system supplies key markets. Natural gas sales (millions of cubic feet per day) 3,764 3,452 2,937

Special Items Results for 1998 included a charge for inventory Global gas marketing purchases natural gas and natural gas valuation adjustments of $108 million to reflect lower products from our upstream operations and others for resale, market prices for crude oil and refined products, employee and operates natural gas processing plants and pipelines in separation costs of $20 million associated with various the United States. cost-cutting initiatives, mostly in the U.K., Panama TEXACO 1998 ANNUAL REPORT 35

Our global gas marketing results in both 1998 and 1997 Special Items Results for 1998 included a charge of $18 mil- were adversely affected by losses associated with our start-up lion for employee separation costs associated with our wholesale and retail marketing activities in the United corporate center reorganization and other cost-cutting ini- Kingdom. We exited the U.K. wholesale gas marketing tiatives which are expected to reduce annual pre-tax costs by business in October 1998. Weak natural gas and natural gas $60 million. Also included in 1998 results are tax benefits liquids margins in the U.S. also contributed to the poor of $43 million for the sales of interests in a subsidiary and a results. Milder than normal temperatures reduced demand benefit of $25 million to adjust for prior years’ federal tax and squeezed margins. In 1996, natural gas marketing mar- liabilities. The year 1997 included a tax benefit of $488 mil- gins in the U.S. were strong, especially in the first quarter. lion for an IRS settlement. Results for 1996 included a charge of $43 million for employee separation costs, a tax Special Items Results for 1998 included employee separation benefit of $188 million from the sale of an interest in a costs of $3 million associated with an announced restructur- subsidiary, a tax benefit of $41 million from adjusting prior ing and a gain of $20 million on the sale of an interest years’ state tax expenses, and a charge of $32 million for in our Discovery pipeline affiliate. The restructuring is expense accruals for litigation issues. expected to yield annual pre-tax cost savings of $20 million. Other Items

LOOKING FORWARD IN GLOBAL GAS MARKETING Liquidity and Capital Resources

Operations will focus on more profitable trading markets. INTRODUCTION The Statement of Consolidated Cash Flows We will also exit the retail gas marketing business in the on page 45 reports the changes in cash balances for the last United Kingdom. three years, and summarizes the inflows and outflows of cash between operating, investing and financing activities. Our Other Business Units cash-requirement strategy is to rely on cash from operations, supplemented by outside borrowings and the proceeds from (Millions of dollars) 1998 1997 1996 the sale of non-strategic assets. Operating income $ 7 $ 5 $ 10 The main components of cash flows are:

Our other business units include insurance activity and INFLOWS Cash from operating activities represents net income power generation and gasification operations. There were no adjusted for non-cash charges or credits, such as deprecia- significant items in our three-year results. tion, depletion and amortization, and changes in working capital and other balances. Cash from operating activities Corporate/Non-operating excludes exploratory expenses, which we show as an invest- (Millions of dollars) 1998 1997 1996 ing activity. In 1998, cash from operating activities of Results before special items $ (412) $ (415) $ (404) $2,544 million is significantly lower than the prior year pri- Special items: marily due to lower prices. For more detailed insight into Employee separation costs (18) — (43) our financial and operational results, see Analysis of Income Tax benefits on asset sales 43 — 188 by Operating Segments on the preceding pages. Tax and other issues 25 488 9 Net new borrowings in 1998 were $1,052 million Total special items 50 488 154 compared to $498 million in 1997. Our strong cash man- Total Corporate/ agement policies have provided us with the resources to Non-operating $ (362) $ 73 $ (250) obtain cash necessary to supplement our funding require- ments when faced with deteriorating market conditions Corporate/Non-operating includes our corporate center and such as lower crude oil and natural gas prices. During the financing activities. Over the last three years, our corporate year, we borrowed $280 million associated with assets in and non-operating results before special items have been the U.K. North Sea, $691 million from our existing “shelf ” relatively flat. The year 1998 includes lower overhead and registrations, including $191 million under our medium- tax expense as well as higher interest income mostly offset term note program, and $94 million from the issuance of by interest expense from higher average debt levels. Zero Coupon Notes in Brazil. We also increased the amount 36 TEXACO 1998 ANNUAL REPORT

of our commercial paper by $725 million during the year, Purchases of common stock were $579 million in 1998 — In to a total of $1.6 billion at year-end. See Note 10 to the the first quarter of 1998, we purchased $105 million of our financial statements for total outstanding debt, including common stock. In March 1998, we announced our intention 1998 borrowings. to purchase up to an additional $1 billion of our common After December 31, 1998, we issued an additional stock, subject to market conditions, through open market $500 million from our existing “shelf” registration to refi- purchases or privately negotiated transactions. Under this nance existing short-term debt. program, we purchased $474 million in the second and third quarters of 1998. Purchases under this program have been suspended for an indefinite period. We maintain strong credit The following table reflects our key financial indicators: ratings and access to global (Millions of dollars, except as indicated) 1998 1997 1996 financial markets providing Current ratio 1.07 1.07 1.24 us flexibility to borrow funds Total debt $ 7,291 $ 6,392 $ 5,590 at low capital costs. Average years debt maturity 10 11 12 Average interest rates 7.0% 7.2% 7.5% Minority interest in Our senior debt is rated A+ by Standard & Poor’s subsidiary companies $ 679 $ 645 $ 658 Corporation and A1 by Moody’s Investors Service. Our U.S. Stockholders’ equity $ 11,833 $ 12,766 $ 10,372 commercial paper is rated A-1 by Standard & Poor’s and Total debt to total borrowed Prime-1 by Moody’s. These ratings denote high quality and invested capital 36.8% 32.3% 33.6% investment grade securities. Our debt has an average matu- rity of 10 years and a weighted average interest rate of OUTLOOK We consider our financial position to be sufficiently 7.0%. We also maintain $2.05 billion in revolving credit strong to meet our anticipated future financial requirements. facilities, which remain unused, to provide additional sup- Our financial policies and procedures afford us flexibility to port for liquidity and our commercial paper program. meet the changing landscape of our financial environment Cash from affiliates of $612 million was received from while assuring that the appropriate safeguards are in effect Equilon, representing formation payments. In February to provide adequate internal controls for all transactions. 1999, we received $101 million from Equilon for the pay- Cash required to service debt maturities in 1999 is projected ment of notes receivable. to be about $500 million, which we intend to refinance. While projections for a low price scenario extend OUTFLOWS Capital and exploratory expenditures (Capex) were through 1999, we feel that our cash from operating activities, $3,101 million in 1998 — The section on page 37 coupled with our borrowing capacity, will allow us to meet describes in more detail the uses of our Capex dollars. our Capex requirements and continue to provide substantial return to our shareholders in the form of dividends.

We continue our commitment MANAGING MARKET RISK We are exposed to the following to return value to our share- types of market risks: holders through a sustained ➤ The price of crude oil, natural gas and petroleum products dividend policy. ➤ The value of foreign currencies in relation to the U.S. dollar ➤ Interest rates Payments of dividends were $1,057 million in 1998 — $952 million to common, $53 million to preferred and $52 million to shareholders who hold a minority interest in Texaco subsidiary companies. TEXACO 1998 ANNUAL REPORT 37

We enter into arrangements such as futures contracts, swaps CAPITAL AND EXPLORATORY EXPENDITURES — FUNCTIONAL and options to manage our exposure to these risks within (Billions of dollars) established guidelines. Our written policies for engaging in $6 these transactions limit our exposure and do not allow for speculation. These arrangements do not expose us to mater- $5 ial adverse effects. See Notes 10, 15 and 16 to the financial statements and Supplemental Market Risk Disclosures on page 76 for additional information. $4

Capital and Exploratory Expenditures $3 1998 ACTIVITY Worldwide capital and exploratory expendi- tures, including our share of affiliates, were $4.0 billion for the year 1998, $5.9 billion for 1997 and $3.4 billion in $2 1996. The year 1997 included the $1.4 billion acquisition of Monterey Resources Inc., a producing company primarily $1 in California. Excluding this acquisition, Texaco’s expendi- tures in 1998 reflect the deferral of certain projects due to the low-price environment. Expenditures were geographi- cally and functionally split as follows: 1996 1997 1998 Acquisition of Monterey Resources

CAPITAL AND EXPLORATORY EXPENDITURES — GEOGRAPHICAL Manufacturing, marketing, distribution and other (Billions of dollars) Global gas marketing Exploration and production $6 Continued emphasis on exploration and production projects.

$5

EXPLORATION AND PRODUCTION Significant areas of invest- $4 ment included: ➤ High-impact development and exploratory projects in $3 the deepwater Gulf of Mexico ➤ Enhanced oil recovery spending in California and $2 Indonesia ➤ Exploratory activity in promising international areas, $1 including Nigeria, the U.K., Angola and Trinidad ➤ Development work in the U.K. North Sea, Indonesia and other promising areas 1996 1997 1998 ➤ Continued investments, though at a slowed pace, in Eurasia Acquisition of Monterey Resources International MANUFACTURING, MARKETING AND DISTRIBUTION AND OTHER United States Investments in downstream facilities included: Balanced spending on a worldwide portfolio of projects. ➤ Refining and marketing investments by two newly formed alliances in the United States ➤ Marketing expansion throughout promising areas of Latin America ➤ Investments associated with the Caltex refinery in Thailand 38 TEXACO 1998 ANNUAL REPORT

The following table details our capital and exploratory expenditures:

1998 1997 1996 Inter- Inter- Inter- (Millions of dollars) U.S. national Total U.S. national Total U.S. national Total Exploration and production Exploratory expenses $ 257 $ 204 $ 461 $ 189 $ 282 $ 471 $ 153 $ 226 $ 379 Capital expenditures Acquisition of Monterey Resources Inc. — — — 1,448 — 1,448 — — — Other 1,182 1,068 2,250 1,406 1,127 2,533 990 902 1,892 Total exploration and production 1,439 1,272 2,711 3,043 1,409 4,452 1,143 1,128 2,271 Manufacturing, marketing and distribution 433 726 1,159 429 848 1,277 357 658 1,015 Global gas marketing 115 — 115 142 2 144 103 7 110 Other 33 1 34 55 2 57 33 2 35 Total $ 2,020 $ 1,999 $ 4,019 $ 3,669 $ 2,261 $ 5,930 $ 1,636 $ 1,795 $ 3,431 Total, excluding affiliates $ 1,528 $ 1,496 $ 3,024 $ 3,421 $ 1,718 $ 5,139 $ 1,535 $ 1,338 $ 2,873

1999 AND BEYOND Spending for 1999 is expected to be Caltex Group of Companies. The following table provides $3.7 billion. We realize that future profitability is in large our environmental expenditures for the past three years: part dependent upon successful investments today. Even in (Millions of dollars) 1998 1997 1996 the current low-price environment, we feel it is important to continue to prudently allocate capital resources on pro- Capital expenditures $ 175 $ 162 $ 185 jects which often have long lead times and which will Non-capital: generate attractive returns in the future. Ongoing operations 495 538 561 In the upstream, development spending will be directed Remediation 93 79 111 toward projects in the U.S. deepwater Gulf of Mexico, the Restoration and U.K. North Sea and Denmark. Major exploration projects abandonment 44 46 48 will include Nigeria, Angola and Trinidad. In the down- Total environmental stream, capital requirements funded by our affiliates Equilon, expenditures $ 807 $ 825 $ 905 Motiva and Caltex, will be slightly lower in 1999. In the European and Latin American downstream areas, 80% of CAPITAL EXPENDITURES the expenditures relate to marketing operations. Most of the Our spending for capital projects in 1998 was $175 mil- manufacturing capital will be spent at the Pembroke plant lion. These expenditures were made to comply with clean in the U.K. We will also increase our capital spending for air and water regulations as well as waste management power generation projects, mostly through affiliates. requirements. In the United States, reformulated gasoline must meet more stringent emission requirements in the Environmental Matters year 2000. As a result, additional investments will be made The cost of compliance with federal, state and local environ- to meet these new standards. Worldwide capital expendi- mental laws in both the U.S. and international continues to tures projected for 1999 and 2000 are $194 million and be substantial. Using definitions and guidelines established $183 million. by the American Petroleum Institute, our 1998 environ- mental spending was $807 million. This includes our ONGOING OPERATIONS equity share in the environmental expenditures of our major In 1998, environmental expenses charged to current opera- affiliates, Equilon, Motiva and its predecessor Star, and the tions were $495 million. These expenses related largely to the production of cleaner-burning gasoline and the manage- ment of our environmental programs. TEXACO 1998 ANNUAL REPORT 39

REMEDIATION New Accounting Standards Remediation Costs and Liabilities Our worldwide remediation Note 2 to the financial statements discusses accounting expenditures in 1998 were $93 million. This included standards adopted in 1998. $14 million spent on the remediation of Superfund waste In June 1998, SFAS 133, “Accounting for Derivative sites. At the end of 1998, we had liabilities of $468 million Instruments and Hedging Activities,” was issued. SFAS 133 for the estimated cost of our known environmental liabili- establishes new accounting rules and disclosure requirements ties. This includes $46 million for the cleanup of Superfund for most derivative instruments and for hedging related to waste sites. We have accrued for these remediation liabili- those instruments. We will adopt this Statement effective ties based on currently available facts, existing technology January 1, 2000 and are currently assessing the initial and presently enacted laws and regulations. It is not possi- effects of adoption. ble to project overall costs beyond amounts disclosed due to the uncertainty surrounding future developments in regula- Euro Conversion tions or until new information becomes available. On January 1, 1999, 11 of the 15 member countries of the European Union established fixed conversion rates between Superfund Sites Under the Comprehensive Environmental their existing legacy currencies and one common currency Response, Compensation and Liability Act (CERCLA), the — the euro. The euro began trading on world currency U.S. Environmental Protection Agency (EPA) and other reg- exchanges and may be used in business transactions. On ulatory agencies have identified us as a potentially January 1, 2002, new euro-denominated bills and coins will responsible party (PRP) for cleanup of hazardous waste sites. be issued, and legacy currencies will be completely with- We have determined that we may have potential exposure, drawn from circulation by June 30 of that year. though limited in most cases, at 260 multi-party hazardous Our operating subsidiaries affected by the euro conver- waste sites. Of these sites, 73 are on the EPA’s National sion have been actively addressing our computer systems Priority List. Under Superfund, liability is joint and several, and overall fiscal and operational activities to ensure our that is, each PRP at a site can be held liable individually for euro readiness. We are adapting our computer, financial and the entire cleanup cost of the site. We are, however, actively operating systems and equipment to accommodate euro- pursuing the sharing of Superfund costs with other identi- denominated transactions. We are also reviewing our mar- fied PRP’s. The sharing of these costs is on the basis of keting and operational policies and procedures to ensure our weight, volume and toxicity of the materials contributed by ability to continue to successfully conduct all aspects of our the PRP. business in this new, price-transparent market. We believe that the euro conversion will not have a material adverse RESTORATION AND ABANDONMENT COSTS AND LIABILITIES impact on our financial condition or results of operations. Expenditures in 1998 for restoration and abandonment amounted to $44 million. At year-end 1998, accruals to Year 2000 cover the cost of restoration and abandonment or “closure” THE PROBLEM The Year 2000 (Y2K) problem concerns of our oil and gas producing properties were $851 million. the inability of information and technology based operating systems to properly recognize and process date-sensitive information beyond December 31, 1999. This could result We make every reasonable effort to fully comply with in systems failures and miscalculations, which could cause applicable governmental regulations. Changes in these reg- business disruptions. Equipment that uses a date, such as ulations as well as our continuous re-evaluation of our computers and operating control systems, may be affected. environmental programs may result in additional future This includes equipment used by our customers and suppli- costs. We believe that any mandated future costs would ers, as well as by utilities and governmental entities that be recoverable in the marketplace, since all companies provide critical services to us. within our industry would be facing similar requirements. However, we do not believe that such future costs will be material to our financial position or to our operating results over any reasonable period of time. 40 TEXACO 1998 ANNUAL REPORT

OUR STATE OF READINESS We started working on the Y2K RISKS Certain Y2K risk factors which could have a material problem in early 1995. By early 1996, we formed a adverse effect on our results of operations, liquidity and Business Unit Steering Team and a Corporate Year 2000 financial condition include, but are not limited to: failure to Office. Our progress is reported monthly to our Chief identify critical systems which will experience failures, Executive Officer, and quarterly to our Board of Directors. errors in efforts to correct problems, unexpected failures by Additionally, we are actively performing both internal audits key business suppliers and customers, extended failures by and external reviews to ensure that we reach our objectives. public and private utility companies or common carriers We recognize that the Y2K issue affects every aspect of supplying services to us and failures in global banking sys- our business, including computer software, computer hard- tems and capital markets. ware, telecommunications, industrial automation and If we have missed a potential Y2K problem, it will most relationships with our suppliers and customers. Our Y2K likely be in our financial software, or in auxiliary systems in effort has included an extensive program to educate our our operations, such as laboratory analyzers and alarm log- employees, and development of detailed guidelines for pro- ging functions, where we have found the majority of the ject management, testing and remediation. Each business problems. We do not anticipate that a problem in these unit is periodically graded on their progress toward reach- areas will have a significant impact on our ability to pursue ing their project milestones. Our major affiliates have our primary business objectives. We routinely analyze all of undertaken similar programs. our production and automation systems for potential fail- In our computers and computer software, most of the ures and appropriate responses are identified and problems we have found involve our corporate financial soft- documented. Any problems in our primary industrial ware applications. Approximately 95% of these need some automation systems can be dealt with using our existing type of modification or upgrade. In our industrial automa- engineering procedures. tion systems, which we use in our refinery, lubricant plant, The worst case scenario would be that our failure or fail- gas plant and oil well operations to monitor, control and log ures by our important suppliers and customers to correct data about the processes, approximately 5% need modifica- material Y2K problems could result in serious disruptions tion or upgrade. The majority of these are auxiliary systems, in normal business activities and operations. Such disrup- such as laboratory analyzers and alarm logging functions, tions could prevent us from producing crude oil and natural but several of the higher level supervisory data acquisition gas, and manufacturing and delivering refined products to systems and flow metering systems also require upgrades. customers. For example, failure by a utility company to deliver electricity to our producing operations could cause us to shut-in production leading to lost sales and income. At the end of 1998, we were We do not expect a worst case scenario. However, if it approximately 80% through our occurs, Y2K failures, if not corrected on a timely basis or Y2K efforts of inventorying, otherwise mitigated by our contingency plans, could have a material adverse effect on our results of operations, liquidity assessing and fixing our systems. and overall financial condition.

CONTINGENCY PLANS We are well into our program to iden- Almost all systems should be ready by the end of the first tify and assess our Y2K readiness and the Y2K readiness of quarter of 1999, but a few will be delayed until later in our critical and important suppliers and customers. We will 1999 as we wait for vendor upgrades. If any of these late- either seek alternative suppliers and customers for those we scheduled upgrades are delayed, we will seek alternate assess as risky, or we will develop and test contingency vendors or develop contingency plans, as appropriate. We plans. We have begun to develop these contingency plans. are also progressing in our reviews with critical suppliers In addition, we are reviewing our existing business resump- and customers as to their Y2K state of readiness. tion plans. We expect to arrange alternative suppliers or develop and complete the testing of contingency plans no COSTS Because we began early, we have been able to do most later than July 1, 1999. of the work ourselves. This has kept our costs low, and we project that we will spend no more than $75 million on making our systems Y2K ready. As of December 31, 1998, we have incurred costs of approximately $37 million. TEXACO 1998 ANNUAL REPORT 41

Description of Significant Accounting Policies

Principles of Consolidation Investments and Advances The consolidated financial statements consist of the We use the equity method of accounting for investments in accounts of Texaco Inc. and subsidiary companies owned certain affiliates owned 50% or less, including corporate directly or indirectly more than 50% except when voting joint ventures, limited liability companies and partnerships. control does not exist. Intercompany accounts and transac- Under this method, we record equity in the pre-tax income tions are eliminated. or losses of limited liability companies and partnerships, The U.S. dollar is the functional currency of all our oper- and in the net income or losses of corporate joint-venture ations and substantially all of the operations of affiliates companies currently in Texaco’s revenues, rather than when accounted for on the equity method. For these operations, realized through dividends or distributions. translation effects and all gains and losses from transac- We record the net income of affiliates accounted for at tions not denominated in the functional currency are cost in net income when realized through dividends. included in income currently, except for certain hedging We account for investments in debt securities and in transactions. The cumulative translation effects for the equity securities with readily determinable fair values at fair equity affiliates using functional currencies other than the value if classified as available-for-sale. U.S. dollar are included in the currency translation adjust- ment in stockholders’ equity. Properties, Plant and Equipment and Depreciation, Depletion and Amortization Use of Estimates We follow the “successful efforts” method of accounting for In preparing Texaco’s consolidated financial statements in our oil and gas exploration and producing operations. accordance with generally accepted accounting principles, We capitalize as incurred the lease acquisition costs we are required to use estimates and management’s judg- of properties held for oil, gas and mineral production. ment. While we have considered all available information, We expense as incurred exploratory costs other than wells. actual amounts could differ from those reported as assets We initially capitalize exploratory wells, including strati- and liabilities and related revenues, costs and expenses and graphic test wells, pending further evaluation of whether the disclosed amounts of contingencies. economically recoverable proved reserves have been found. If such reserves are not found, we charge the well costs to Revenues exploratory expenses. For locations not requiring major cap- We recognize revenues for crude oil, natural gas and refined ital expenditures, we record the charge within one year of product sales at the point of passage of title specified in the well completion. We capitalize intangible drilling costs of contract. We record revenues on forward sales where cash productive wells and of development dry holes, and tangible has been received to deferred income until the passage of equipment costs. Also capitalized are costs of injected car- title during delivery. bon dioxide related to development of oil and gas reserves. We base our evaluation of impairment for properties, Cash Equivalents plant and equipment intended to be held on comparison of We generally classify highly liquid investments with a carrying value against undiscounted future net pre-tax cash maturity of three months or less when purchased as cash flows, generally based on proved developed reserves. If an equivalents. impairment is identified, we adjust the asset’s carrying amount to fair value. We generally account for assets to be Inventories disposed of at the lower of net book value or fair value less We value inventories at the lower of cost or market, after cost to sell. initial recording at cost. For virtually all inventories of We amortize unproved oil and gas properties, when crude oil, petroleum products and petrochemicals, cost is individually significant, by property using a valuation determined on the last-in, first-out (LIFO) method. For assessment. We generally amortize other unproved oil and other merchandise inventories, cost is on the first-in, first- gas properties on an aggregate basis over the average out (FIFO) method. For materials and supplies, cost is at holding period, for the portion expected to be nonproduc- average cost. tive. We amortize productive properties and other tangible and intangible costs of producing activities principally by field. Amortization is based on the unit-of-production basis by applying the ratio of produced oil and gas to 42 TEXACO 1998 ANNUAL REPORT

estimated recoverable proved oil and gas reserves. We assets are assessed individually by type for this purpose. include estimated future restoration and abandonment costs This process requires the use of estimates and judgment, as in determining amortization and depreciation rates of pro- many deferred income tax assets have a long potential real- ductive properties. ization period. We apply depreciation of facilities other than producing We do not make provision for possible income taxes properties generally on the group plan, using the straight- payable upon distribution of accumulated earnings of for- line method, with composite rates reflecting the estimated eign subsidiary companies and affiliated corporate useful life and cost of each class of property. We depreciate joint-venture companies when such earnings are deemed to facilities not on the group plan individually by estimated be permanently reinvested. useful life using the straight-line method. We exclude esti- mated salvage value from amounts subject to depreciation. Accounting for Contingencies We amortize capitalized nonmineral leases over the esti- Certain conditions may exist as of the date financial state- mated useful life of the asset or the lease term, as appropriate, ments are issued, which may result in a loss to the company, using the straight-line method. but which will only be resolved when one or more future We record periodic maintenance and repairs at manu- events occur or fail to occur. Such contingent liabilities are facturing facilities on the accrual basis. We charge to expense assessed by the company’s management and legal counsel. normal maintenance and repairs of all other properties, The assessment of loss contingencies necessarily involves plant and equipment as incurred. We capitalize renewals, an exercise of judgment and is a matter of opinion. In betterments and major repairs that materially extend the assessing loss contingencies related to legal proceedings that useful life of properties and record a retirement of the assets are pending against the company or unasserted claims that replaced, if any. may result in such proceedings, the company’s legal counsel When capital assets representing complete units of evaluates the perceived merits of any legal proceedings or property are disposed of, we credit or charge to income unasserted claims as well as the perceived merits of the the difference between the disposal proceeds and net amount of relief sought or expected to be sought therein. book value. If the assessment of a contingency indicates that it is probable that a material liability had been incurred and the Environmental Expenditures amount of the loss can be estimated, then the estimated When remediation of a property is probable and the liability would be accrued in the company’s financial state- related costs can be reasonably estimated, we expense ments. If the assessment indicates that a potentially environmentally-related remediation costs and record them material liability is not probable, but is reasonably possible, as liabilities. We expense or capitalize other environmental or is probable but cannot be estimated, then the nature of expenditures, principally maintenance or preventive in the contingent liability, together with an estimate of the nature, as appropriate. range of possible loss if determinable and material, would be disclosed. Deferred Income Taxes Loss contingencies considered remote are generally not We determine deferred income taxes utilizing a liability disclosed unless they involve guarantees, in which case the approach. The income statement effect is derived from nature of the guarantee would be disclosed. However, in changes in deferred income taxes on the balance sheet. This some instances in which disclosure is not otherwise required, approach gives consideration to the future tax consequences the company may disclose contingent liabilities of an associated with differences between financial accounting and unusual nature which, in the judgment of management and tax bases of assets and liabilities. These differences relate to its legal counsel, may be of interest to stockholders or others. items such as depreciable and depletable properties, exploratory and intangible drilling costs, nonproductive Statement of Consolidated Cash Flows leases, merchandise inventories and certain liabilities. This We present cash flows from operating activities using the approach gives immediate effect to changes in income tax indirect method. We exclude exploratory expenses from laws upon enactment. cash flows of operating activities and apply them to cash We reduce deferred income tax assets by a valuation flows of investing activities. On this basis, we reflect all cap- allowance when it is more likely than not (more than 50%) ital and exploratory expenditures as investing activities. that a portion will not be realized. Deferred income tax TEXACO 1998 ANNUAL REPORT 43

Statement of Consolidated Income

(Millions of dollars) For the years ended December 31 1998 1997 1996

Revenues Sales and services (includes transactions with significant affiliates of $4,169 million in 1998, $3,633 million in 1997 and $3,867 million in 1996) $ 30,910 $ 45,187 $ 44,561 Equity in income of affiliates, interest, asset sales and other 797 1,480 939 Total revenues 31,707 46,667 45,500

Deductions Purchases and other costs (includes transactions with significant affiliates of $1,669 million in 1998, $2,178 million in 1997 and $2,048 million in 1996) 24,179 35,230 34,643 Operating expenses 2,508 3,251 3,235 Selling, general and administrative expenses 1,224 1,755 1,803 Exploratory expenses 461 471 379 Depreciation, depletion and amortization 1,675 1,633 1,455 Interest expense 480 412 434 Taxes other than income taxes 423 520 496 Minority interest 56 68 72 31,006 43,340 42,517

Income before income taxes and cumulative effect of accounting change 701 3,327 2,983 Provision for income taxes 98 663 965 Income before cumulative effect of accounting change 603 2,664 2,018 Cumulative effect of accounting change (25) — — Net income $ 578 $ 2,664 $ 2,018

Net Income per Common Share (Dollars) Basic: Income before cumulative effect of accounting change $ 1.04 $ 4.99 $ 3.77 Cumulative effect of accounting change (.05) — — Net income $ .99 $ 4.99 $ 3.77 Diluted: Income before cumulative effect of accounting change $ 1.04 $ 4.87 $ 3.68 Cumulative effect of accounting change (.05) — — Net income $ .99 $ 4.87 $ 3.68 Average Number of Common Shares Outstanding (for computation of earnings per share) (thousands) Basic 528,416 522,234 520,392 Diluted 528,965 542,570 541,824

See accompanying notes to consolidated financial statements. 44 TEXACO 1998 ANNUAL REPORT

Consolidated Balance Sheet

(Millions of dollars) As of December 31 1998 1997

Assets Current Assets Cash and cash equivalents $ 249 $ 311 Short-term investments – at fair value 22 84 Accounts and notes receivable (includes receivables from significant affiliates of $694 million in 1998 and $234 million in 1997), less allowance for doubtful accounts of $28 million in 1998 and $22 million in 1997 3,955 4,230 Inventories 1,154 1,483 Deferred income taxes and other current assets 256 324 Total current assets 5,636 6,432 Investments and advances 7,184 5,097 Net properties, plant and equipment 14,761 17,116 Deferred charges 989 955 Total $ 28,570 $ 29,600

Liabilities and Stockholders’ Equity Current Liabilities Notes payable, commercial paper and current portion of long-term debt $ 939 $ 885 Accounts payable and accrued liabilities (includes payables to significant affiliates of $395 million in 1998 and $106 million in 1997) Trade liabilities 2,302 2,669 Accrued liabilities 1,368 1,480 Estimated income and other taxes 655 960 Total current liabilities 5,264 5,994 Long-term debt and capital lease obligations 6,352 5,507 Deferred income taxes 1,644 1,825 Employee retirement benefits 1,248 1,224 Deferred credits and other noncurrent liabilities 1,550 1,639 Minority interest in subsidiary companies 679 645 Total 16,737 16,834 Stockholders’ Equity Market auction preferred shares 300 300 ESOP convertible preferred stock 428 457 Unearned employee compensation and benefit plan trust (334) (389) Common stock – 567,606,290 shares issued 1,774 1,774 Paid-in capital in excess of par value 1,640 1,688 Retained earnings 9,561 9,987 Other accumulated nonowner changes in equity (101) (95) 13,268 13,722 Less – Common stock held in treasury, at cost 1,435 956 Total stockholders’ equity 11,833 12,766 Total $ 28,570 $ 29,600

See accompanying notes to consolidated financial statements. TEXACO 1998 ANNUAL REPORT 45

Statement of Consolidated Cash Flows

(Millions of dollars) For the years ended December 31 1998 1997 1996

Operating Activities Net income $ 578 $ 2,664 $ 2,018 Reconciliation to net cash provided by (used in) operating activities Cumulative effect of accounting change 25 — — Depreciation, depletion and amortization 1,675 1,633 1,455 Deferred income taxes (152) 451 (20) Exploratory expenses 461 471 379 Minority interest in net income 56 68 72 Dividends from affiliates, greater than (less than) equity in income 224 (370) 167 Gains on asset sales (109) (558) (19) Changes in operating working capital Accounts and notes receivable 125 718 (1,072) Inventories (51) (56) (104) Accounts payable and accrued liabilities 16 (856) 716 Other – mainly estimated income and other taxes (205) (64) 97 Other – net (99) (186) 73 Net cash provided by operating activities 2,544 3,915 3,762

Investing Activities Capital and exploratory expenditures (3,101) (3,628) (2,897) Proceeds from asset sales 282 1,036 125 Proceeds from sale of discontinued operations — — 344 Sales (purchases) of leasehold interests 25 (503) 261 Purchases of investment instruments (947) (1,102) (1,668) Sales/maturities of investment instruments 1,118 1,096 1,816 Formation payments from U.S. affiliate 612 — — Other – net — (57) 70 Net cash used in investing activities (2,011) (3,158) (1,949)

Financing Activities Borrowings having original terms in excess of three months Proceeds 1,300 507 307 Repayments (741) (637) (802) Net increase (decrease) in other borrowings 493 628 (143) Purchases of common stock (579) (382) (159) Dividends paid to the company’s stockholders Common (952) (918) (859) Preferred (53) (55) (58) Dividends paid to minority stockholders (52) (81) (87) Net cash used in financing activities (584) (938) (1,801)

Cash and Cash Equivalents Effect of exchange rate changes (11) (19) (2) Increase (decrease) during year (62) (200) 10 Beginning of year 311 511 501 End of year $ 249 $ 311 $ 511

See accompanying notes to consolidated financial statements. 46 TEXACO 1998 ANNUAL REPORT

Statement of Consolidated Stockholders’ Equity

Shares Amount Shares Amount Shares Amount (Shares in thousands; amounts in millions of dollars) 1998 1997 1996

Preferred Stock par value $1; Shares authorized – 30,000,000

Market Auction Preferred Shares (Series G, H, I and J) – liquidation preference of $250,000 per share Beginning and end of year 1 $ 300 1 $ 300 1 $ 300 Series B ESOP Convertible Preferred Stock – liquidation value of $600 per share Beginning of year 693 416 720 432 751 450 Retirements (44) (27) (27) (16) (31) (18) End of year 649 389 693 416 720 432 Series F ESOP Convertible Preferred Stock – liquidation value of $737.50 per share Beginning of year 56 41 57 42 60 45 Retirements (3) (2) (1) (1) (3) (3) End of year 53 39 56 41 57 42

Unearned Employee Compensation (related to ESOP preferred stock and restricted stock awards) Beginning of year (149) (175) (234) Awards (36) (16) (22) Amortization and other 91 42 81 End of year (94) (149) (175)

Benefit Plan Trust (common stock) Beginning of year 9,200 (240) 8,000 (203) 8,000 (203) Additions — — 1,200 (37) — — End of year 9,200 (240) 9,200 (240) 8,000 (203)

Common Stock par value $3.125; Shares authorized – 700,000,000 Beginning of year 567,606 1,774 548,587 1,714 548,587 1,714 Issued for Monterey acquisition — — 19,019 60 — — End of year 567,606 1,774 567,606 1,774 548,587 1,714

Common Stock Held in Treasury, at cost Beginning of year 25,467 (956) 21,191 (628) 20,152 (517) Purchases of common stock 9,572 (551) 7,423 (410) 3,515 (159) Transfer to benefit plan trust — — (1,200) 37 — — Other – mainly employee benefit plans (2,063) 72 (1,947) 45 (2,476) 48 End of year 32,976 $ (1,435) 25,467 $ (956) 21,191 $ (628)

See accompanying notes to consolidated financial statements. (Continued on next page) TEXACO 1998 ANNUAL REPORT 47

Statement of Consolidated Stockholders’ Equity

(Millions of dollars) 1998 1997 1996

Paid–in Capital in Excess of Par Value Beginning of year $ 1,688 $ 630 $ 655 Monterey acquisition — 1,091 — Treasury stock transactions relating to investor services plan and employee compensation plans (48) (33) (25) End of year 1,640 1,688 630

Retained Earnings Balance at beginning of year 9,987 8,292 7,186 Add: Net income 578 2,664 2,018 Tax benefit associated with dividends on unallocated ESOP Convertible Preferred Stock 3 4 5 Deduct: Dividends declared on Common stock ($1.80 per share in 1998, $1.75 per share in 1997 and $1.65 per share in 1996) 952 918 859 Preferred stock Series B ESOP Convertible Preferred Stock 38 40 42 Series F ESOP Convertible Preferred Stock 4 4 4 Market Auction Preferred Shares (Series G, H, I and J) 13 11 12 Balance at end of year 9,561 9,987 8,292

Other Accumulated Nonowner Changes in Equity Currency translation adjustment Beginning of year (105) (65) 61 Change during year (2) (40) (126) End of year (107) (105) (65) Minimum pension liability adjustment Beginning of year (16) — — Change during year (8) (16) — End of year (24) (16) — Unrealized net gain on investments Beginning of year 26 33 62 Change during year 4 (7) (29) End of year 30 26 33 Total other accumulated nonowner changes in equity (101) (95) (32)

Stockholders’ Equity End of year (including preceding page) $11,833 $12,766 $10,372

See accompanying notes to consolidated financial statements. 48 TEXACO 1998 ANNUAL REPORT

Statement of Consolidated Nonowner Changes in Equity

(Millions of dollars) 1998 1997 1996

Net income $ 578 $ 2,664 $ 2,018

Other nonowner changes in equity: Currency translation adjustment Reclassification to net income of realized gain on sale of affiliate — — (60) Other unrealized net change during period (2) (40) (66) Total (2) (40) (126) Minimum pension liability adjustment Before income taxes (16) (21) — Income taxes 8 5 — Total (8) (16) — Unrealized net gain on investments Net gain (loss) arising during period Before income taxes 35 22 9 Income taxes (11) (9) (7) Reclassification to net income of net realized (gain) or loss Before income taxes (31) (29) (43) Income taxes 11 9 12 Total 4 (7) (29) Total other nonowner changes in equity (6) (63) (155) Total nonowner changes in equity $ 572 $ 2,601 $ 1,863

See accompanying notes to consolidated financial statements. TEXACO 1998 ANNUAL REPORT 49

Notes to Consolidated Financial Statements

Note 1 Segment Information We are presenting below information about our operating We determined our operating segments based on differ- segments for the years 1998, 1997 and 1996, according ences in the nature of their operations and geographic to Statement of Financial Accounting Standards 131, location. The composition of segments and measure of seg- Disclosures about Segments of an Enterprise and Related ment profit is consistent with that used by our Executive Information, which we adopted this year. Council in making strategic decisions. The Executive Council is headed by the Chairman and Chief Executive Officer and includes, among others, the Senior Vice Presidents hav- ing oversight responsibility for our business units.

Operating Segments 1998

After Income Sales and Services Tax Tax Other Capital Assets at Inter- Profit Expense DD&A Non-cash Expen- Year- (Millions of dollars) Outside segment Total (Loss) (Benefit) Expense Items ditures End Exploration and production United States $ 1,712 $ 1,660 $ 3,372 $ 301 $ 34 $ 892 $ 1 $ 1,200 $ 8,699 International 2,028 1,358 3,386 120 127 513 20 951 4,352 Manufacturing, marketing and distribution United States 2,582 107 2,689 223 96 6 228 1 4,095 International 19,835 86 19,921 332 130 204 135 403 8,306 Global gas marketing 4,692 84 4,776 (18) 5 14 50 61 879 Segment totals $ 30,849 $ 3,295 34,144 958 392 1,629 434 2,616 26,331 Other business units 91 7 4 2 (2) — 506 Corporate/Non-operating 4 (362) (298) 44 (67) 33 1,945 Intersegment eliminations (3,329) — — — — — (212) Consolidated, before cumulative effect of accounting change $ 30,910 $ 603 $ 98 $ 1,675 $ 365 $ 2,649 $ 28,570

Operating Segments 1997

After Income Sales and Services Tax Tax Other Capital Assets at Inter- Profit Expense DD&A Non-cash Expen- Year- (Millions of dollars) Outside segment Total (Loss) (Benefit) Expense Items ditures End Exploration and production United States $ 365 $ 4,156 $ 4,521 $ 990 $ 487 $ 783 $ 281 $ 1,349 $ 8,769 International 2,575 1,751 4,326 807 566 442 105 934 4,036 Manufacturing, marketing and distribution United States 16,992 357 17,349 324 172 178 169 262 5,668 International 19,992 235 20,227 508 117 173 (166) 482 8,048 Global gas marketing 5,207 254 5,461 (43) (9) 14 61 75 1,012 Segment totals $ 45,131 $ 6,753 51,884 2,586 1,333 1,590 450 3,102 27,533 Other business units 101 5 5 2 4 — 544 Corporate/Non-operating 6 73 (675) 41 242 57 2,030 Intersegment eliminations (6,804) — — — — — (507) Consolidated $ 45,187 $ 2,664 $ 663 $ 1,633 $ 696 $ 3,159 $ 29,600 50 TEXACO 1998 ANNUAL REPORT

Operating Segments 1996

After Income Sales and Services Tax Tax Other Capital Assets at Inter- Profit Expense DD&A Non-cash Expen- Year- (Millions of dollars) Outside segment Total (Loss) (Benefit) Expense Items ditures End Exploration and production United States $ 204 $ 4,146 $ 4,350 $ 1,074 $ 528 $ 670 $ 109 $ 990 $ 6,067 International 2,384 1,930 4,314 493 523 393 (21) 755 3,651 Manufacturing, marketing and distribution United States 18,424 493 18,917 210 143 176 92 271 6,310 International 18,750 363 19,113 447 127 161 201 356 7,751 Global gas marketing 4,754 342 5,096 34 19 13 (7) 110 1,152 Segment totals $ 44,516 $ 7,274 51,790 2,258 1,340 1,413 374 2,482 24,931 Other business units 112 10 10 7 3 — 530 Corporate/Non-operating 5 (250) (385) 35 332 35 2,216 Intersegment eliminations (7,346) — — — — — (714) Consolidated $ 44,561 $ 2,018 $ 965 $ 1,455 $ 709 $ 2,517 $ 26,963

Our exploration and production segments explore for, find, Corporate and non-operating includes the assets, income develop and produce crude oil and natural gas. The U.S. and expenses relating to cash management and financing segment includes minor operations in Canada. Our manu- activities, our corporate center and other items not directly facturing, marketing and distribution segments process attributable to the operating segments. crude oil and other feedstock into refined products and pur- We apply the same accounting policies to each of the chase, sell and transport crude oil and refined petroleum segments as we do in preparing the consolidated financial products. Global gas marketing purchases natural gas and statements. Intersegment sales and services are generally natural gas products from our exploration and production representative of market prices or arms-length negotiated operations and others for resale, and operates natural gas transactions. Intersegment receivables are representative of processing plants and pipelines in the United States. This normal trade balances. Other non-cash items principally segment, which operates primarily in the U.S., sold its U.K. include deferred income taxes, the difference between cash wholesale gas business in 1998 and announced its intention distributions and equity in income of affiliates, and non- to dispose of its U.K. retail gas marketing business as well. cash charges and credits associated with asset sales. Capital Other business units include our insurance, power genera- expenditures are presented on a cash basis, excluding tion and gasification operations and investments in exploratory expenses. undeveloped mineral properties. None of these units is indi- The countries in which we have significant sales and ser- vidually significant in terms of revenue, income or assets. vices and long-lived assets are listed below. Sales and services You are encouraged to read Note 6 – Investments and are based on the origin of the sale. Long-lived assets include Advances, beginning on page 52, which includes informa- properties, plant and equipment and investments in foreign tion about our affiliates and the formation of the Equilon producing operations where the host governments own the and Motiva alliances in 1998. physical assets under terms of the operating agreements.

Sales and Services Long-lived assets at December 31 (Millions of dollars) 1998 1997 1996 1998 1997 1996 United States $ 8,184 $ 21,657 $ 22,643 $ 8,757 $11,437 $ 8,683 International – Total 22,726 23,530 21,918 6,250 5,876 4,914 Significant countries included above: Brazil 3,175 3,175 2,670 301 266 235 Netherlands 1,636 1,901 2,129 257 250 212 United Kingdom 7,529 6,862 5,846 2,257 2,384 1,846 TEXACO 1998 ANNUAL REPORT 51

Note 2 Adoption of New Accounting Standards SFAS 128 and 129 — During 1997, we adopted SFAS 128, Institute of Certified Public Accountants. This Statement “Earnings per Share.” Our basic and diluted net income per requires that the costs of start-up activities and organization common share under SFAS 128 were approximately the costs, as defined, be expensed as incurred. The cumulative same as under the comparable prior basis of reporting. In effect of adoption on Texaco’s net income for 1998 was a net 1997, we also adopted SFAS 129, “Disclosure of loss of $25 million. This Statement will be adopted by Information about Capital Structure.” Our existing disclo- Texaco and our other affiliates effective January 1, 1999. We sures complied with this standard. do not expect the effect to be material. SFAS 130, 131 and 132 — In 1998, Texaco adopted SFAS 130, 131 and 132. SFAS 130, “Reporting Comprehen- Note 3 Income Per Common Share sive Income,” requires that we report all items classified as Basic net income per common share is based on net income comprehensive income under its provisions as separate com- less preferred stock dividend requirements divided by the ponents within a financial statement. SFAS 131, “Disclosures average number of common shares outstanding. Diluted net about Segments of an Enterprise and Related Information,” income per common share assumes issuance of the net incre- requires the reporting of certain income, revenue, expense mental shares from stock options and full conversion of all and asset data about operating segments of public enterprises. dilutive convertible securities at the later of the beginning Operating segments are based upon a company’s internal of the year or date of issuance. Common shares held by the management structure. SFAS 131 also requires data for rev- benefit plan trust are not considered outstanding for pur- enues and long-lived assets by major countries of operation. poses of net income per common share. SFAS 132, “Employer’s Disclosures about Pensions and In July 1997, the Board of Directors approved a two- Other Postretirement Benefits,” requires disclosure of new for-one split of the company’s common stock, effective information on changes in plan benefit obligations and fair September 29, 1997. The par value was halved and the num- values of plan assets. ber of authorized shares was doubled. We have restated SOP 98-5 — Effective January 1, 1998, Caltex, our affil- prior years’ financial statements and all references to number iate, adopted Statement of Position 98-5, “Reporting on the of shares and per share amounts for the stock split. Also, Costs of Start-Up Activities,” issued by the American we have adjusted all agreements that include exchange, con- version or other rights based on the company’s common stock for the stock split.

1998 1997 1996 (Millions, except per share amounts) For the years ended December 31 Income Shares Per Share Income Shares Per Share Income Shares Per Share

Basic net income: Income before cumulative effect of accounting change $ 603 $ 2,664 $ 2,018 Less: Preferred stock dividends (54) (56) (58) Income before cumulative effect of accounting change, for basic income per share $ 549 528.4 $ 1.04 $ 2,608 522.2 $ 4.99 $ 1,960 520.4 $ 3.77

Effect of dilutive securities: ESOP Convertible preferred stock — — 34 19.3 34 20.0 Stock options and restricted stock — .4 — .8 — 1.1 Convertible debentures 1 .2 — .3 — .3 Income before cumulative effect of accounting change, for diluted income per share $ 550 529.0 $ 1.04 $ 2,642 542.6 $ 4.87 $ 1,994 541.8 $ 3.68 52 TEXACO 1998 ANNUAL REPORT

Note 4 Acquisition of Monterey Resources Note 6 Investments and Advances In November 1997, we acquired all of the outstanding We account for our investments in affiliates, including cor- common stock of Monterey Resources (Monterey) in porate joint ventures and partnerships owned 50% or less, exchange for approximately 19 million shares of our on the equity method. Our total investments and advances common stock valued at $1.1 billion. We accounted for the are summarized as follows: transaction as a purchase. The total purchase price was (Millions of dollars) $1.4 billion, including existing Monterey debt of $.3 bil- As of December 31 1998 1997 lion; $2.2 billion was assigned to properties, plant and Affiliates accounted for equipment, and $.7 billion was assigned to deferred income on the equity method tax liabilities. Monterey was an oil and gas company with Exploration and production mostly crude oil properties in California. United States $ 230 $ 126 Our financial statements reflect the consolidation of International Monterey assets and liabilities at fair value effective from CPI 452 437 November 1, 1997. The pro forma effects had Monterey Other 24 15 been consolidated at the beginning of either 1997 or 1996 706 578 would not have been material to Texaco’s revenues, net Manufacturing, marketing income, and basic and diluted net income per common and distribution share for those years. United States Equilon 2,266 — Note 5 Inventories Motiva 896 — (Millions of dollars) Star — 889 As of December 31 1998 1997 Other 29 178 Crude oil $ 116 $ 308 International Petroleum products and petrochemicals 799 893 Caltex 1,747 1,860 Other merchandise 40 59 Other 215 191 Materials and supplies 199 223 5,153 3,118 Total $ 1,154 $1,483 Global gas marketing 71 55 Other affiliates 86 70 The book value of inventories at December 31, 1998 is net Total 6,016 3,821 of a valuation allowance of $99 million to adjust from cost to market. At December 31, 1997, the excess of estimated Miscellaneous investments, market over the book value of inventories was $204 million. long-term receivables, etc., accounted for at: Fair value 470 537 Cost, less reserve 698 739 Total $ 7,184 $ 5,097 TEXACO 1998 ANNUAL REPORT 53

Our equity in the net income of affiliates is adjusted to $2 billion. Caltex’ net income for 1996 includes a gain of reflect income taxes for limited liability companies and $621 million associated with this sale. Our results include partnerships whose income is directly taxable to us: a net gain of $219 million relating to this sale, comprised of our equity share of the gain, less an adjustment in the (Millions of dollars) For the years ended December 31 1998 1997 1996 carrying value of our investment and further reduced by a Equity in net income (loss) tax on the dividend distributed to the shareholders. Exploration and production United States $ 37 $ 40 $ 36 Equilon Enterprises LLC International Effective January 1, 1998, Texaco and Shell Oil Company CPI 107 171 188 formed Equilon Enterprises LLC (Equilon), a Delaware lim- Other (12) — 1 ited liability company. Equilon is a joint venture that 132 211 225 combined major elements of the companies’ western and Manufacturing, marketing midwestern U.S. refining and marketing businesses and and distribution their nationwide trading, transportation and lubricants United States businesses. We own 44% and Shell Oil Company owns 56% Equilon 199 — — of Equilon. Motiva 22 — — The carrying amounts at January 1, 1998, of the princi- Star (3) 95 14 pal assets and liabilities of the businesses we contributed to Other 3 48 51 Equilon were $.2 billion of net working capital assets, International $2.8 billion of net properties, plant and equipment and Caltex (36) 252 347 $.2 billion of debt. These amounts were reclassified to Other 15 20 22 investment in affiliates accounted for by the equity method. 200 415 434 In April 1998, we received $463 million from Equilon, Global gas marketing (26) (20) (3) representing reimbursement of certain capital expenditures Other affiliates 12 10 13 incurred prior to the formation of the joint venture. In July Total $ 318 $ 616 $ 669 1998, we received $149 million from Equilon for certain Dividends received $ 709 $ 332 $ 878 specifically identified assets transferred for value to Equilon.

The undistributed earnings of these affiliates included in our Motiva Enterprises LLC retained earnings were $2,409 million, $2,658 million and Effective July 1, 1998, Texaco, Shell and Saudi Aramco $2,609 million as of December 31, 1998, 1997 and 1996. formed Motiva Enterprises LLC (Motiva), a Delaware lim- ited liability company. Motiva is a joint venture that Caltex Group combined Texaco’s and Saudi Aramco’s interests and major We have investments in the Caltex Group of Companies, elements of Shell’s eastern and Gulf Coast U.S. refining and owned 50% by Texaco and 50% by Chevron Corporation. marketing businesses. Texaco’s and Saudi Aramco’s interest The Caltex group consists of P.T. Caltex Pacific Indonesia in these businesses were previously conducted by Star (CPI), American Overseas Petroleum Limited and subsidiary Enterprise (Star), a joint-venture partnership owned 50% by and Caltex Corporation and subsidiaries (Caltex). This Texaco and 50% by Saudi Refining, Inc., a corporate affili- group of companies is engaged in the exploration for and ate of Saudi Aramco. Texaco and Saudi Refining, Inc., each production, transportation, refining and marketing of crude owns 32.5% and Shell owns 35% of Motiva. oil and products in Africa, Asia, Australia, the Middle East The investment in Motiva at date of formation approxi- and New Zealand. mated the previous investment in Star. The Motiva Results for the Caltex Group in 1998 include an after- investment and previous Star investment are recorded as tax charge of $50 million (Texaco’s share $25 million) for investment in affiliates accounted for on the equity method. the cumulative effect of accounting change. See Note 2 for additional information. In 1996, Caltex completed the sale of its 50% interest The following table provides summarized financial infor- in Nippon Petroleum Refining Company, Limited (NPRC) mation on a 100% basis for the Caltex Group, Equilon, to its partner, Nippon Oil Company, for approximately Motiva, Star and all other affiliates that we account for on 54 TEXACO 1998 ANNUAL REPORT

the equity method, as well as Texaco’s share. The net income market value on the date of formation of Star. Our invest- of all limited liability companies and partnerships is net ment and equity in the income of Motiva and Star, as of estimated income taxes. The actual income tax liability is reported in our consolidated financial statements, reflect the reflected in the accounts of the respective members or part- remaining unamortized historical carrying cost of the assets ners and not shown in the following table. transferred to Star at formation of Star. Additionally, our Motiva’s and Star’s assets at the respective balance sheet investments in Motiva and Star include adjustments neces- dates include the remaining portion of the assets which sary to reflect contractual arrangements on the formation of were originally transferred from Texaco to Star at the fair Star, principally involving contributed inventories.

Total Caltex Other Texaco’s (Millions of dollars) Equilon Motiva Star Group Affiliates Share

1998 Gross revenues $ 22,246 $ 5,371 $ 3,190 $17,174 $ 2,541 $22,856 Income (loss) before income taxes and cumulative effect of accounting change $ 502 $ 78 $ (128) $ 519 $ 170 $ 662 Net income (loss) $ 326 $ 51 $ (83) $ 143 $ 84 $ 318 As of December 31: Current assets $ 2,648 $ 1,435 $ 1,974 $ 687 $ 2,757 Noncurrent assets 7,758 5,306 7,684 2,021 9,332 Current liabilities (4,058) (1,248) (2,840) (727) (3,932) Noncurrent liabilities (382) (1,665) (2,421) (672) (2,141) Net equity $ 5,966 $ 3,828 $ 4,397 $ 1,309 $ 6,016

Total Caltex Other Texaco’s (Millions of dollars) Star Group Affiliates Share

1997 Gross revenue $ 7,758 $18,357 $ 4,028 $14,641 Income before income taxes $ 301 $ 1,210 $ 605 $ 940 Net income $ 196 $ 846 $ 400 $ 616 As of December 31: Current assets $ 1,042 $ 2,521 $ 947 $ 1,965 Noncurrent assets 3,260 7,193 3,607 6,324 Current liabilities (769) (2,991) (1,032) (2,270) Noncurrent liabilities (1,072) (2,131) (2,022) (2,198) Net equity $ 2,461 $ 4,592 $ 1,500 $ 3,821

Total Caltex Other Texaco’s (Millions of dollars) Star Group Affiliates Share

1996 Gross revenue $ 8,006 $18,166 $ 3,940 $14,644 Income before income taxes $ 38 $ 2,175 $ 697 $ 1,310 Net income $ 25 $ 1,193 $ 451 $ 669 As of December 31: Current assets $ 816 $ 2,681 $ 1,049 $ 1,937 Noncurrent assets 3,204 6,714 3,853 6,354 Current liabilities (704) (2,999) (1,182) (2,329) Noncurrent liabilities (1,141) (2,140) (1,845) (2,151) Net equity $ 2,175 $ 4,256 $ 1,875 $ 3,811 TEXACO 1998 ANNUAL REPORT 55

Note 7 Properties, Plant and Equipment

Gross Net (Millions of dollars) As of December 31 1998 1997 1998 1997 Exploration and production United States $ 21,993 $ 21,698 $ 7,963 $ 7,951 International 7,532 6,789 2,929 2,692 Total 29,525 28,487 10,892 10,643

Manufacturing, marketing and distribution United States 74 4,600 26 2,743 International 4,486 4,309 3,054 2,894 Total 4,560 8,909 3,080 5,637

Global gas marketing 647 593 271 224

Other 762 967 518 612 Total $ 35,494 $ 38,956 $ 14,761 $ 17,116 Capital lease amounts included above $ 264 $ 450 $ 79 $ 105

Accumulated depreciation, depletion and amortization totaled $20,733 million and $21,840 million at December 31, 1998 and 1997. Interest capitalized as part of properties, plant and equipment was $21 million in 1998, $20 million in 1997 and $12 million in 1996.

In 1998, we recorded pre-tax charges of $150 million for the international exploration and production operating seg- write-downs of impaired assets. These charges were recorded ments. These charges were recorded to depreciation, to depreciation, depletion and amortization expense. depletion and amortization expense. Fair values were based In the U.S. exploration and production operating on expected future discounted cash flows. segment, pre-tax asset write-downs for impaired properties in Louisiana and Canada were $64 million. The Louisiana Note 8 Foreign Currency property represents an unsuccessful enhanced recovery Currency translations resulted in a pre-tax loss of $80 mil- project. We determined in the fourth quarter of 1998 that lion in 1998, $59 million in 1997 and $60 million in 1996. the carrying value of this property exceeded future undis- After applicable taxes, 1998 included a loss of $94 million counted cash flows. Fair value was determined by discounting compared to a gain of $154 million in 1997 and a loss of expected future cash flows. Canadian properties were impaired $66 million in 1996. following our decision in October 1998 to exit the upstream After-tax currency impacts for the years 1998 and 1997 business in Canada. These properties were written down to were largely due to currency volatility in Asia. In 1998, our their sales price with the sale closing in December 1998. Caltex affiliate incurred significant currency-related losses In the international exploration and production operat- due to the strengthening of the Korean won and Japanese ing segment, the pre-tax asset write-down for the impair- yen against the U.S. dollar. In contrast, those currencies ment of our investment in the Strathspey field in the U.K. weakened against the U.S. dollar in 1997 which resulted in North Sea was $58 million. The Strathspey impairment was significant currency-related gains. caused by a downward revision in the fourth quarter of the Results for 1996 through 1998 were also impacted by estimated volume of the field’s proved reserves. Fair value the effect of currency rate changes on deferred income taxes was determined by discounting expected future cash flows. denominated in British pounds. In 1998 and 1996, the U.S. In the U.S. downstream operating segment, the pre-tax dollar weakened against that currency causing us to record asset write-downs for the impairment of surplus facilities losses of $5 million and $58 million. In 1997, when the and equipment not transferred to the Equilon joint venture U.S. dollar strengthened, we recorded a gain of $28 million. was $28 million. Fair value was determined by an indepen- Effective October 1, 1997, Caltex changed the func- dent appraisal. tional currency for its operations in its Korean and Japanese In 1997, we recorded pre-tax charges of $63 million for affiliates to the U.S. dollar. the write-downs of impaired assets. These assets, consisting Currency translation adjustments shown in the separate of producing properties and gas plants, were in the U.S. and stockholders’ equity account result from translation items 56 TEXACO 1998 ANNUAL REPORT

pertaining to certain affiliates of Caltex. For the years 1998, The deferred income tax assets and liabilities included in 1997 and 1996 these adjustments were losses of $2 million, the Consolidated Balance Sheet as of December 31, 1998 $40 million and $126 million. The year 1996 includes the and 1997 amounted to $205 million and $145 million, as reversal of $60 million of previously deferred gains which net current assets and $1,644 million and $1,825 million, were recognized in earnings due to the sale by Caltex of its as net noncurrent liabilities. The table that follows shows investment in its Japanese affiliate, NPRC. deferred income tax assets and liabilities by category:

(Liability) Asset Note 9 Taxes (Millions of dollars) As of December 31 1998 1997 (Millions of dollars) 1998 1997 1996 Depreciation $ (1,079) $ (1,054) Federal and other income taxes Depletion (429) (601) Current Intangible drilling costs (726) (826) U.S. Federal $ (45) $ (538) $ 359 Other deferred tax liabilities (686) (755) Foreign 283 689 642 Total (2,920) (3,236) State and local 12 61 (16) Total 250 212 985 Employee benefit plans 532 526 Deferred Tax loss carryforwards 641 728 U.S. (104) 457 13 Tax credit carryforwards 368 237 Foreign (48) (6) (33) Environmental liabilities 116 167 Total (152) 451 (20) Other deferred tax assets 639 580 Total income taxes 98 663 965 Total 2,296 2,238 Taxes other than income taxes Total before valuation allowance (624) (998) Oil and gas production 70 127 114 Valuation allowance (815) (682) Property 108 139 119 Total $ (1,439) $ (1,680) Payroll 119 125 120 Other 126 129 143 The preceding table excludes certain potential deferred Total 423 520 496 income tax asset amounts for which possibility of realization Import duties and other levies is extremely remote. U.S. 36 53 38 The valuation allowance relates principally to upstream Foreign 6,843 5,414 4,127 operations in Denmark. The related deferred income tax Total 6,879 5,467 4,165 assets result from tax loss carryforwards and book versus Total direct taxes 7,400 6,650 5,626 tax asset basis differences for hydrocarbon tax. Loss carry- Taxes collected from consumers 2,148 3,370 3,237 forwards from this tax are generally determined by Total all taxes $ 9,548 $ 10,020 $ 8,863 individual field and, in that case, are not usable against other fields’ taxable income. TEXACO 1998 ANNUAL REPORT 57

The following schedule reconciles the differences between For the years 1998 and 1997, no loss carryforward bene- the U.S. Federal income tax rate and the effective income fits were recorded for U.S. Federal income taxes. For the year tax rate excluding the cumulative effect of accounting change 1996, we recorded a benefit of $184 million for loss carry- in 1998: forwards. For the years 1998, 1997 and 1996, the tax benefits recorded for loss carryforwards were $30 million, 1998 1997 1996 $31 million and $16 million in foreign income taxes. U.S. Federal income tax rate At December 31, 1998, we had worldwide tax basis loss assumed to be applicable 35.0% 35.0% 35.0% carryforwards of approximately $1,692 million, including IRS settlement — (14.7) — $967 million which do not have an expiration date. The Net earnings and dividends remainder expire at various dates through 2019. attributable to affiliated Foreign tax credit carryforwards available for U.S. Federal corporations accounted income tax purposes amounted to approximately $113 mil- for on the equity method (7.0) (4.7) (5.5) lion at December 31, 1998, expiring at various dates through Aggregate earnings and 2003. Alternative minimum tax and other tax credit carry- losses from international forwards available for U.S. Federal income tax purposes were operations 10.4 6.2 12.7 $368 million at December 31, 1998, of which $317 million Tax adjustments (8.7) (.3) (.4) have no expiration date. The remaining credits expire at Sales of stock of subsidiaries (6.1) — (6.3) various dates through 2013. The credits that are not uti- Energy credits (11.7) (1.4) (1.9) lized by the expiration dates may be taken as deductions for Other 2.1 (.2) (1.2) U.S. Federal income tax purposes. For the year 1998, we Effective income tax rate 14.0% 19.9% 32.4% recorded tax credit carryforwards of $52 million for U.S. Federal income tax purposes. The year 1997 included a $488 million benefit resulting from an IRS settlement. Note 10 Short-Term Debt, Long-Term Debt, For companies operating in the United States, pre-tax Capital Lease Obligations and Related earnings before the cumulative effect of an accounting Derivatives change aggregated $194 million in 1998, $1,527 million in Notes Payable, Commercial Paper and Current 1997 and $1,783 million in 1996. For companies with Portion of Long-term Debt operations located outside the United States, pre-tax earnings on that basis aggregated $507 million in 1998, $1,800 mil- (Millions of dollars) As of December 31 1998 1997 lion in 1997 and $1,200 million in 1996. Notes payable to banks and others Income taxes paid, net of refunds, amounted to with originating terms of $430 million, $285 million and $917 million in 1998, one year or less $ 368 $ 473 1997 and 1996. Commercial paper 1,617 892 The undistributed earnings of subsidiary companies and Current portion of long-term debt of affiliated corporate joint-venture companies accounted for and capital lease obligations on the equity method, for which deferred U.S. income taxes Indebtedness 991 1,005 have not been provided at December 31, 1998, amounted Capital lease obligations 13 15 to $1,328 million and $2,226 million. The corresponding 2,989 2,385 amounts at December 31, 1997 were $1,482 million and Less short-term obligations $2,313 million. Determination of the unrecognized U.S. intended to be refinanced 2,050 1,500 deferred income taxes on these amounts is not practicable. Total $ 939 $ 885 58 TEXACO 1998 ANNUAL REPORT

The weighted average interest rates of commercial paper The percentages shown for variable-rate debt are the interest and notes payable to banks at December 31, 1998 and 1997 rates at December 31, 1998. The percentages shown for the were 5.9% and 6.1%. categories “Medium-term notes” and “Other long-term debt” are the weighted average interest rates at year-end 1998. Long-term Debt and Capital Lease Obligations Where applicable, principal amounts shown in the preced- ing schedule include unamortized premium or discount. (Millions of dollars) As of December 31 1998 1997 Interest paid, net of amounts capitalized, amounted to Long-Term Debt $474 million in 1998, $395 million in 1997 and $433 mil- 3-1/2% convertible notes due 2004 $ 204 $ 205 lion in 1996. 5.7% notes due 2008 201 — At December 31, 1998, we had revolving credit facilities 6% notes due 2005 299 — with commitments of $2.05 billion with syndicates of 6-7/8% notes due 1999 200 200 major U.S. and international banks. These facilities are 6-7/8% debentures due 2023 196 195 available as support for our issuance of commercial paper as 7.09% notes due 2007 150 150 well as for working capital and other general corporate 7-1/2% debentures due 2043 198 198 purposes. We had no amounts outstanding under these 7-3/4% debentures due 2033 199 199 facilities at year-end 1998. We pay commitment fees on 8% debentures due 2032 147 147 these facilities. The banks reserve the right to terminate the 8-1/4% debentures due 2006 150 150 credit facilities upon the occurrence of certain specific 8-3/8% debentures due 2022 198 198 events, including change in control. 8-1/2% notes due 2003 199 199 At December 31, 1998, our long-term debt included 8-5/8% debentures due 2010 150 150 $2.05 billion of short-term obligations scheduled to mature 8-5/8% debentures due 2031 199 199 during 1999, which we have both the intent and the ability 8-5/8% debentures due 2032 199 199 to refinance on a long-term basis through the use of our 8.65% notes due 1998 — 200 $2.05 billion revolving credit facilities. 8-7/8% debentures due 2021 150 150 Contractual annual maturities of long-term debt, includ- 9% notes due 1999 200 200 ing sinking fund payments and potential repayments 9-3/4% debentures due 2020 250 250 resulting from options that debtholders might exercise, for 10.61% notes due 2005 — 206 the five years subsequent to December 31, 1998 are as Medium-term notes, maturing follows (in millions): from 1999 to 2043 (7.5%) 543 489 Revolving Credit Facility, 1999 2000 2001 2002 2003 due 1999-2002 – $ 991 $ 211 $ 219 $ 246 $ 272 variable rate (5.9%) 309 330 Pollution Control Revenue Bonds, Debt-related Derivatives due 2012 – variable rate (3.3%) 166 166 We seek to maintain a balanced capital structure that pro- Other long-term debt: vides financial flexibility and supports our strategic Texaco Inc. – Guarantee of ESOP objectives while achieving a low cost of capital. This is Series F loan – variable rate (6.6%) 2 76 achieved by balancing our liquidity and interest rate expo- U.S. dollars (6.5%) 335 417 sures. We manage these exposures primarily through Other currencies (11.2%) 394 20 long-term and short-term debt on the balance sheet. As part Total 5,238 4,893 of our interest rate exposure management, we seek to bal- Capital Lease Obligations (see Note 11) 68 134 ance the benefit of the lower cost of floating rate debt, with 5,306 5,027 its inherent increased risk, with fixed rate debt having less Less current portion of long-term market risk. To achieve this objective, we also use off- debt and capital lease obligations 1,004 1,020 balance sheet derivative instruments, primarily interest rate 4,302 4,007 swaps, to manage identifiable exposures on a non-leveraged, Short-term obligations intended non-speculative basis. to be refinanced 2,050 1,500 Summarized below are the carrying amounts and fair val- Total long-term debt and ues of our debt and debt-related derivatives at December 31, capital lease obligations $ 6,352 $ 5,507 1998 and 1997, excluding a combined interest rate and TEXACO 1998 ANNUAL REPORT 59

equity swap entered into in 1997. Derivative usage during Fair values of debt are based upon quoted market prices, the periods presented was limited to interest rate swaps, as well as rates currently available to us for borrowings with where we either paid or received the net effect of a fixed rate similar terms and maturities. We estimate the fair value of versus a floating rate (commercial paper or LIBOR) index at swaps as the amount that would be received or paid to ter- specified intervals, calculated by reference to an agreed minate the agreements at year-end, taking into account notional principal amount. current interest rates and the current creditworthiness of the swap counterparties. The notional amounts of derivative (Millions of dollars) As of December 31 1998 1997 contracts do not represent cash flow and are not subject to Notes Payable and Commercial Paper: credit risk. Carrying amount $ 1,985 $ 1,365 Amounts receivable or payable based on the interest Fair value 1,985 1,365 rate differentials of derivatives are accrued monthly and Related Derivatives – are reflected in interest expense as a hedge of interest on Payable (Receivable): outstanding debt. Gains and losses on terminated swaps are Carrying amount $ — $ — deferred and amortized over the life of the associated debt or Fair value 17 3 the original term of the swap, whichever is shorter. Notional principal amount $ 300 $ 300 Weighted average maturity (years) 8.3 9.3 Note 11 Lease Commitments and Weighted average fixed pay rate 6.42% 6.42% Rental Expense Weighted average floating We have leasing arrangements involving service stations, receive rate 5.32% 6.09% tanker charters, crude oil production and processing equip- ment and other facilities. We reflect amounts due under Long-Term Debt, including capital leases in our balance sheet as obligations, while we Current maturities: reflect our interest in the related assets as properties, plant Carrying amount $ 5,238 $ 4,893 and equipment. The remaining lease commitments are Fair value 5,842 5,289 operating leases, and we record payments on such leases as Related Derivatives – rental expense. Payable (Receivable): As of December 31, 1998, we had estimated minimum Carrying amount $ — $ — commitments for payment of rentals (net of noncancelable Fair value (9) (1) sublease rentals) under leases which, at inception, had a Notional principal amount $ 449 $ 544 noncancelable term of more than one year, as follows: Weighted average maturity (years) 8.4 .7 Weighted average fixed receive rate 6.24% 5.71% (Millions of dollars) Operating Leases Capital Leases Weighted average floating pay rate 5.03% 5.76% 1999 $ 154 $ 13 Unamortized net gain on 2000 112 12 terminated swaps 2001 95 18 Carrying amount $ 5 $ 8 2002 323 8 2003 56 8 Excluded from this table is an interest rate and equity swap After 2003 320 21 with a notional principal amount of $200 million entered Total lease commitments $ 1,060 $ 80 into in 1997, related to the 3-1/2% notes due 2004. We Less interest 12 pay floating rate and receive fixed rate. Also, the counter- Present value of total capital party assumes all exposure for the potential equity-based lease obligations $ 68 cash redemption premium on the notes. The fair value of this swap at year-end 1998 and 1997 was not material. Operating lease commitments for 2002 include a $213 mil- During 1998, floating rate pay swaps having an aggre- lion residual value guarantee of leased production facilities. gate notional principal amount of $503 million were Payment is required only if we do not renew the lease. amortized or matured. We initiated $466 million of new floating rate pay swaps. There was no activity in fixed rate pay swaps during 1998. 60 TEXACO 1998 ANNUAL REPORT

Rental expense relative to operating leases, including Series B and Series F used to service debt of the Plans are tax contingent rentals based on factors such as gallons sold, is deductible to the company. In November 1998 and provided in the table below. Such payments do not include December 1997, a portion of the original Thrift Plan ESOP rentals on leases covering oil and gas mineral rights. loan was refinanced through a company loan. The refinanc- ing will extend the ESOP for a period of up to six years. (Millions of dollars) 1998 1997 1996 We reflect in our long-term debt the plans’ original Rental expense ESOP loans guaranteed by Texaco Inc. As we repay the orig- Minimum lease rentals $ 208 $ 270 $ 259 inal and refinanced ESOP loans, we reduce the remaining Contingent rentals — 3 10 ESOP-related unearned employee compensation included as Total 208 273 269 a component of stockholders’ equity. Less rental income on properties subleased Benefit Plan Trust to others 50 78 53 We have established a benefit plan trust for funding com- Net rental expense $ 158 $ 195 $ 216 pany obligations under some of our benefit plans. At year-end 1998, the trust contained 9.2 million shares of Note 12 Employee Benefit Plans treasury stock. We intend to continue to pay our obligations Texaco Inc. and certain of its non-U.S. subsidiaries sponsor under our benefit plans. The trust will use the shares, pro- various benefit plans for active employees and retirees. The ceeds from the sale of such shares and dividends on such costs of the savings, health care and life insurance plans rela- shares to pay benefits only to the extent that we do not pay tive to employees’ active service are shared by the company such benefits. The trustee will vote the shares held in the and its employees, with Texaco’s costs for these plans charged trust as instructed by the trust’s beneficiaries. The shares to expense as incurred. In addition, reserves for employee held by the trust are not considered outstanding for benefit plans are provided principally for the unfunded costs earnings per share purposes until distributed or sold by the of various pension plans, retiree health and life insurance trust in payment of benefit obligations. benefits, incentive compensation plans and for separation benefits payable to employees. Termination Benefits In the fourth quarter of 1998, we recorded an after-tax Employee Stock Ownership Plans (ESOP) charge of $80 million for employee separations, curtailment We recorded ESOP expense of $1 million in 1998, $2 mil- costs and special termination benefits associated with our lion in 1997 and $15 million in 1996. Our contributions to previously-announced restructuring of our worldwide the Employees Thrift Plan of Texaco Inc. and the Employees upstream and natural gas businesses, along with our corpo- Savings Plan of Texaco Inc. amounted to $1 million in rate center restructuring and other cost-cutting initiatives, 1998, $2 million in 1997 and $26 million in 1996. These primarily in the international downstream areas. The charge plans are designed to provide participants with a benefit of was comprised of $88 million of operating expenses, $27 mil- approximately 6% of base pay, as well as any benefits earned lion of selling, general and administrative expenses and under the current employee Performance Compensation $35 million in related income tax benefits. Under the re- Program. ESOP expenses in 1996 included $9 million for structuring program, we estimate that over 1,400 employee the 1995 employee incentive award program. reductions worldwide will occur, substantially by the end of In 1998, 1997 and 1996, we paid $42 million, $44 mil- the first quarter of 1999. Through December 31, 1998, we lion and $46 million in dividends on Series B and Series F have terminated 433 employees and we paid $15 million of stock. The trustee applies the dividends to fund interest benefits under this program. The remaining benefits will payments which amounted to $5 million, $7 million and be paid in future periods in accordance with plan provisions. $10 million for 1998, 1997 and 1996, as well as to reduce We recorded an after-tax charge of $56 million in the principal on the ESOP loans. Dividends on the shares of fourth quarter of 1996 to cover the costs of employee TEXACO 1998 ANNUAL REPORT 61

separations, including employees of affiliates, as a result of a Pension Plans companywide realignment and consolidation of our opera- We sponsor pension plans that cover the majority of our tions. We recorded an adjustment of $6 million in the employees. Generally, these plans provide defined pension fourth quarter of 1997 to increase the accrual from the pre- benefits based on years of service and final average pay. vious amount. The program was completed by the end of Pension plan assets are principally invested in equity and fixed 1997 with the reduction of approximately 920 employees. income securities and deposits with insurance companies. During 1998, we paid $8 million of benefits under this pro- Total worldwide expense for all employee pension plans gram. The remaining benefits of $12 million will be paid in of Texaco, including pension supplementations and smaller future periods in accordance with plan provisions. non-U.S. plans, was $92 million in 1998 and 1997 and $91 million in 1996. The following data are provided for principal U.S. and non-U.S. plans:

Pension Benefits 1998 1997 Other U.S. Benefits (Millions of dollars) As of December 31 U.S. Int’l U.S. Int’l 1998 1997

Changes in Benefit (Obligations) Benefit (obligations) at January 1 $ (1,769) $ (835) $ (1,657) $ (801) $ (756) $ (699) Service cost (60) (21) (54) (17) (9) (6) Interest cost (117) (86) (117) (85) (50) (49) Amendments — (3) (18) — — (5) Actuarial gain/(loss) (191) (117) (85) (74) 8 (39) Employee contributions (4) (3) (4) (1) (12) (10) Benefits paid 240 70 182 59 56 53 Curtailments/settlements 17 — — — (7) — Special termination benefits (12) — — (1) (3) — Currency adjustments — 16 — 85 — — Acquisitions/joint ventures 12 — (16) — — (1) Benefit (obligations) at December 31 $ (1,884) $ (979) $ (1,769) $ (835) $ (773) $ (756)

Changes in Plan Assets Fair value of plan assets at January 1 $ 1,702 $ 900 $ 1,483 $ 829 $ — $ — Actual return on plan assets 293 142 304 166 — — Company contributions 90 32 87 27 44 43 Employee contributions 4 3 4 1 12 10 Expenses (6) (2) (5) (2) — — Benefits paid (240) (70) (182) (59) (56) (53) Currency adjustments — 23 — (62) — — Acquisitions/joint ventures (17) — 11 — — — Fair value of plan assets at December 31 $ 1,826 $ 1,028 $ 1,702 $ 900 $ — $ — 62 TEXACO 1998 ANNUAL REPORT

Pension Benefits 1998 1997 Other U.S. Benefits (Millions of dollars) As of December 31 U.S. Int’l U.S. Int’l 1998 1997

Funded Status of the Plans Obligation (greater than) less than assets $ (58) $ 49 $ (67) $ 65 $ (773) $ (756) Unrecognized net transition asset (14) (14) (21) (23) — — Unrecognized prior service cost 68 52 85 46 4 5 Unrecognized actuarial (gain)/loss (93) 4 (100) (53) (92) (94) Net (liability)/asset recorded in Texaco’s Consolidated Balance Sheet $ (97) $ 91 $ (103) $ 35 $ (861) $ (845)

Net (liability)/asset recorded in Texaco’s Consolidated Balance Sheet consists of: Prepaid benefit asset $ 72 $ 346 $ 64 $ 303 $ — $ — Accrued benefit liability (215) (268) (195) (299) (861) (845) Intangible asset 23 12 21 22 — — Other accumulated nonowner equity 23 1 7 9 — — Net (liability)/asset recorded in Texaco’s Consolidated Balance Sheet $ (97) $ 91 $ (103) $ 35 $ (861) $ (845)

Assumptions as of December 31 Discount rate 6.75% 9.5% 7.0% 10.9% 6.75% 7.0% Expected return on plan assets 10.0% 8.4% 10.0% 8.5% — — Rate of compensation increase 4.0% 6.1% 4.0% 6.2% 4.0% 4.0% Health care cost trend rate — — — — 4.0% 4.0%

Pension Benefits 1998 1997 1996 Other U.S. Benefits (Millions of dollars) As of December 31 U.S. Int’l U.S. Int’l U.S. Int’l 1998 1997 1996

Components of Net Periodic Benefit Expenses Service cost $ 60 $ 21 $ 54 $ 17 $ 57 $ 16 $ 9 $ 6 $ 12 Interest cost 117 86 117 85 117 81 50 49 51 Expected return on plan assets (136) (79) (132) (66) (130) (64) — — — Amortization of transition asset (4) (10) (5) (8) (5) (8) — — — Amortization of prior service cost 11 7 10 6 10 6 — — — Amortization of (gain)/loss 6 (2) 3 — 3 2 (4) (5) (1) Curtailments/settlements 6 — — — — — 1 — — Special termination charges 8 — — — — — 2 — — Net periodic benefit expense $ 68 $ 23 $ 47 $ 34 $ 52 $ 33 $ 58 $ 50 $ 62

For pension plans with accumulated obligations in excess of $414 million, $383 million and $0 as of December 31, plan assets, the projected benefit obligation, accumulated 1998, and $412 million, $384 million and $11 million as benefit obligation and fair value of plan assets were of December 31, 1997. TEXACO 1998 ANNUAL REPORT 63

We acquired Monterey on November 1, 1997, including specified portion of the shares to vest. Restricted perfor- their pension and postretirement benefit plans. We amended mance shares awarded in each year under the plan were as our plans to authorize Monterey to become a participating follows: employer in our plans. In connection with the formation of 1998 1997 1996 Equilon, effective January 1, 1998, we transferred to Equilon pension benefit obligations of $12 million and related plan Shares 334,798 281,174 282,476 assets of $17 million. Weighted average fair value $ 61.59 $ 55.09 $ 42.43

Other U.S. Benefits Stock options granted under the plan extend for 10 years We sponsor postretirement plans in the U.S. that provide from the date of grant and vest over a two year period at a health care and life insurance for retirees and eligible depen- rate of 50% in the first year and 50% in the second year. dents. Our U.S. health insurance obligation is our fixed The exercise price cannot be less than the fair market value dollar contribution. The plans are unfunded, and the costs of the underlying shares of common stock on the date of are shared by us and our employees and retirees. Certain of the grant. The plan provides for restored options. This fea- the company’s non-U.S. subsidiaries have postretirement ture enables a participant who exercises a stock option by benefit plans, the cost of which is not significant to the exchanging previously acquired common stock or who has company. For measurement purposes, the fixed dollar con- shares withheld by us to satisfy tax withholding obliga- tribution is expected to increase by 4% per annum for all tions, to receive new options equal to the number of shares future years. exchanged or withheld. The restored options are fully exer- A change in our fixed dollar contribution has a signifi- cisable six months after the date of grant and the exercise cant effect on the amounts we report. A 1% change in our price is the fair market value of the common stock on the contributions would have the following effects: day the restored option is granted. We apply APB Opinion 25 in accounting for our stock- 1-Percentage 1-Percentage based compensation programs. Stock-based compensation (Millions of dollars) Point Increase Point Decrease expense recognized in connection with the plan was $17 mil- Effect on annual total of service lion in 1998, $18 million in 1997 and $13 million in 1996. and interest cost components $ 5 $ (4) Had we accounted for our plan using the accounting method Effect on postretirement recommended by SFAS 123, net income and earnings per benefit obligation $ 52 $ (45) share would have been the pro forma amounts below:

1998 1997 1996 Note 13 Stock Incentive Plan Net income (Millions of dollars) Under our Stock Incentive Plan, stock options, restricted As reported $ 578 $ 2,664 $ 2,018 stock and other incentive award forms may be granted to Pro forma $ 524 $ 2,621 $ 1,997 executives, directors and key employees to provide motiva- Earnings per share (dollars) tion to enhance the company’s success and increase Basic — as reported $ .99 $ 4.99 $ 3.77 shareholder value. The maximum number of shares that — pro forma $ .89 $ 4.91 $ 3.73 may be awarded as stock options or restricted stock under Diluted — as reported $ .99 $ 4.87 $ 3.68 the plan is 1% of the common stock outstanding on — pro forma $ .89 $ 4.79 $ 3.64 December 31 of the previous year. The following table sum- marizes the number of shares at December 31, 1998, 1997 We used the Black-Scholes model with the following and 1996 available for awards during the subsequent year: assumptions to estimate the fair market value of options at (Shares) As of December 31 1998 1997 1996 date of grant: To all participants 12,677,325 9,607,506 7,027,010 1998 1997 1996 To those participants not Expected life 2 yrs 2 yrs 3 yrs officers or directors 1,967,715 2,362,273 1,932,796 Interest rate 5.4% 6.0% 6.1% Total 14,645,040 11,969,779 8,959,806 Volatility 22.5% 18.6% 15.0% Dividend yield 3.0% 3.0% 3.3% Restricted shares granted under the plan contain a perfor- mance element which must be satisfied in order for all or a 64 TEXACO 1998 ANNUAL REPORT

Option award activity during 1998, 1997 and 1996 is summarized in the following table:

1998 1997 1996 Weighted- Weighted- Weighted- Average Average Average Exercise Exercise Exercise (Stock Options) Shares Price Shares Price Shares Price Outstanding January 1 10,071,307 $ 53.31 9,436,406 $ 42.73 9,335,288 $ 33.45 Granted 2,388,593 61.56 2,084,902 55.06 2,040,530 42.43 Exercised (7,732,978) 53.18 (9,533,861) 44.86 (8,088,040) 34.22 Restored 6,889,941 60.77 8,103,502 55.32 6,271,720 45.52 Canceled (814) 78.08 (19,642) 51.43 (123,092) 36.77 Outstanding December 31 11,616,049 59.48 10,071,307 53.31 9,436,406 42.73 Exercisable December 31 5,945,445 58.93 3,197,262 51.21 2,853,236 39.20 Weighted-average fair value of options granted during the year $ 8.48 $ 6.92 $ 5.50

The following table summarizes information on stock options outstanding at December 31, 1998:

Options Outstanding Options Exercisable Weighted- Weighted- Weighted- Exercisable Price Average Average Average Range (per share) Shares Remaining Life Exercise Price Shares Exercise Price $ 23.39 – 31.84 54,329 3.6 yrs. $ 30.00 54,329 $ 30.00 $ 32.06 – 78.08 11,561,720 6.2 yrs. $ 59.62 5,891,116 $ 59.20 $ 23.39 – 78.08 11,616,049 6.2 yrs. $ 59.48 5,945,445 $ 58.93

Note 14 Preferred Stock and Rights Series B ESOP Convertible Preferred Stock adjusted to one-half Right when we declared a two-for-one At December 31, 1998, the outstanding shares of Series B stock split in 1997. In 1998, our shareholders approved the ESOP Convertible Preferred Stock (Series B) were held by extension of the Rights until May 1, 2004. Unless we an ESOP. Dividends on each share of Series B are cumula- redeem the Rights, the Rights will be exercisable only after tive and payable semiannually at the rate of $57 per annum. a person(s) acquires, obtains the right to acquire or com- Participants may partially convert Series B holdings into mences a tender offer that would result in that person(s) common stock beginning at age 55, and may elect full con- acquiring 20% or more of the outstanding common stock version upon retirement or separation from the company. other than pursuant to a Qualifying Offer. A Qualifying Presently, each share of Series B entitles a participant to Offer is an all-cash, fully financed tender offer for all out- 25.7 votes, voting together with the holders of common standing shares of common stock which remains open for stock, and is convertible into 25.736 shares of common 45 days, which results in the acquiror owning a majority of stock. As an alternative to conversion, a participant can the company’s voting stock, and in which the acquiror elect to receive $600 per share of Series B, payable in cash or agrees to purchase for cash all remaining shares of common common stock. If the participant elects cash, we will cause stock. The Rights entitle holders to purchase from the com- shares of common stock to be sold to fund such election. pany Units of Series D Junior Participating Preferred Stock We may redeem the outstanding shares of Series B at $600 (Series D). In general, each Right entitles the holder to per share, subject to the participants’ right to elect conver- acquire shares of Series D, or in certain cases common stock, sion to common stock at that time. property or other securities at a formula value equal to two times the exercise price of the Right. Series D Junior Participating Preferred Stock We can redeem the Rights at one cent per Right at any and Rights time prior to 10 days after the Rights become exercisable. In 1989, we declared a dividend distribution of one Right Until a Right becomes exercisable, the holder has no addi- for each outstanding share of common stock. This was tional voting or dividend rights and it will not have any TEXACO 1998 ANNUAL REPORT 65

dilutive effect on the company’s earnings. We have reserved speculative purposes. Derivative transactions expose us to and designated 3 million shares as Series D for issuance counterparty credit risk. We place contracts only with par- upon exercise of the Rights. At December 31, 1998, the ties where credit-worthiness has been pre-determined under Rights are not exercisable. credit policies. Also, we employ dollar limits. Therefore, risk of counterparty non-performance and exposure to con- Series F ESOP Convertible Preferred Stock centrations of credit risk are limited. At December 31, 1998, the outstanding shares of Series F ESOP Convertible Preferred Stock were held by an ESOP. CASH AND CASH EQUIVALENTS Fair value approximates cost as Dividends on each share of Series F were cumulative and reflected in the Consolidated Balance Sheet at December 31, payable semiannually at the rate of $64.53 per annum. 1998 and 1997 because of the short-term maturities of On February 16, 1999, each share of Series F was con- these instruments. Cash equivalents are classified as held- verted into 20 shares of common stock, after we called the to-maturity. The amortized cost of cash equivalents at Series F for redemption. December 31, 1998 and 1997 includes $72 million and $129 million of time deposits and $109 million and Market Auction Preferred Shares $47 million of commercial paper. There are outstanding 1,200 shares of cumulative variable rate preferred stock, called Market Auction Preferred Shares. SHORT-TERM AND LONG-TERM INVESTMENTS Fair value is pri- The MAPS are grouped into four series (300 shares each of marily based on quoted market prices and valuation Series G, H, I and J) of $75 million each, with an aggregate statements obtained from major financial institutions. value of $300 million. At December 31, 1998, our available-for-sale securities had The dividend rates for each series are determined by an estimated fair value of $492 million, including gross Dutch auctions conducted at seven-week intervals. unrealized gains and losses of $40 million and $8 million. During 1998, the annual dividend rate for the MAPS At December 31, 1997, our available-for-sale securities had ranged between 3.96% and 4.50% and dividends totaled an estimated fair value of $621 million, including gross $13 million ($11,280, $11,296, $11,227 and $11,218 per unrealized gains and losses of $47 million and $13 million. share for Series G, H, I and J). The available-for-sale securities consist primarily of debt For 1997, the annual dividend rate for the MAPS ranged securities issued by U.S. and foreign governments and cor- between 3.88% and 4.29% and dividends totaled $11 mil- porations. The majority of these investments mature within lion ($9,689, $9,650, $9,675 and $9,774 per share for five years. Series G, H, I and J). For 1996, the annual dividend rate for Proceeds from sales of available-for-sale securities were the MAPS ranged between 3.90% and 4.19% and divi- $1,011 million in 1998, $1,040 million in 1997 and dends totaled $12 million ($9,510, $11,043, $11,009 and $1,503 million in 1996. These sales resulted in gross real- $11,015 per share for Series G, H, I and J). ized gains of $53 million in 1998, $48 million in 1997 We may redeem the MAPS, in whole or in part, at any and $51 million in 1996, and gross realized losses of time at a liquidation preference of $250,000 per share, plus $22 million, $19 million, and $17 million. premium, if any, and accrued and unpaid dividends thereon. The estimated fair value of other long-term investments The MAPS are non-voting, except under limited qualifying as financial instruments but not included above, circumstances. for which it is practicable to estimate fair value, approxi- mated the December 31, 1998 and 1997 carrying values of Note 15 Financial Instruments $331 million and $197 million. In the normal course of our business, we utilize various types of financial instruments. These instruments include SHORT-TERM DEBT, LONG-TERM DEBT AND RELATED DERIVATIVES recorded assets and liabilities, and also items such as deriva- Refer to Note 10 for additional information about debt tives which principally involve off-balance sheet risk. and related derivatives outstanding at December 31, 1998 Derivatives are contracts whose value is derived from and 1997. changes in an underlying commodity price, interest rate or other item. We use derivatives to reduce our exposure to FORWARD EXCHANGE AND OPTION CONTRACTS As an interna- changes in foreign exchange rates, interest rates and crude tional company, we are exposed to currency exchange risk. oil and natural gas prices. We do not use derivatives for To hedge against adverse changes in foreign currency 66 TEXACO 1998 ANNUAL REPORT

exchange rates, we will enter into forward and option con- exchange rates in effect on the balance sheet dates. We tracts to buy and sell foreign currencies. Shown below in record changes in the value of these contracts as part of the U.S. dollars are the notional amounts of outstanding for- carrying amount of the related investments. We record ward exchange contracts to buy and sell foreign currencies. related gains and losses, net of applicable income taxes, to stockholders’ equity until the underlying investments are (Millions of dollars) Buy Sell sold or mature. Australian dollars $ 370 $ 60 British pounds 1,476 440 PREFERRED SHARES OF SUBSIDIARIES Refer to Note 16 regard- Danish krone 449 237 ing derivatives related to subsidiary preferred shares. Dutch guilders 303 13 New Zealand dollars 126 13 PETROLEUM AND NATURAL GAS HEDGING We hedge a portion of Other European currencies 179 77 the market risks associated with our crude oil, natural gas Other currencies 50 43 and petroleum product purchases, sales and exchange activi- Total at December 31, 1998 $ 2,953 $ 883 ties to reduce price exposure. All hedge transactions are Total at December 31, 1997 $ 1,845 $ 606 subject to the company’s corporate risk management policy which sets out dollar, volumetric and term limits, as well Market risk exposure on these contracts is essentially lim- as to management approvals as set forth in our delegations ited to currency rate movements. At year-end 1998, there of authorities. were $8 million unrealized gains and $19 million unreal- We use established petroleum futures exchanges, as well ized losses related to these contracts. At year-end 1997, as “over-the-counter” hedge instruments, including futures, there were $5 million unrealized gains and $29 million options, swaps and other derivative products. In carrying unrealized losses. out our hedging programs, we analyze our major commod- We use forward exchange contracts to buy foreign cur- ity streams for fixed cost, fixed revenue and margin exposure rencies primarily to hedge the net monetary liability to market price changes. Based on this corporate risk pro- position of our European, Australian and New Zealand file, forecasted trends and overall business objectives, we operations and to hedge portions of significant foreign cur- determine an appropriate strategy for risk reduction. rency capital expenditures and lease commitments. These Hedge positions are marked-to-market for valuation contracts generally have terms of 60 days or less. Contracts purposes. Gains and losses on hedge transactions, which off- that hedge foreign currency monetary positions are marked- set losses and gains on the underlying “cash market” to-market monthly. Any resultant gains and losses are transactions, are recorded to deferred income or charges included in income currently as other costs. At year-end until the hedged transaction is closed, or until the antici- 1998 and 1997, hedges of foreign currency commitments pated future purchases, sales or production occur. At that principally involved capital projects requiring expenditure time, any gain or loss on the hedging contract is recorded to of British pounds and Danish krone. The percentages of operating revenues as an increase or decrease in margins, or planned capital expenditures hedged at year-end were: to inventory, as appropriate. British pounds – 54% in 1998 and 62% in 1997; Danish At December 31, 1998 and 1997, there were open deriv- krone – 40% in 1998 and 74% in 1997. Realized gains and ative commodity contracts required to be settled in cash, losses on hedges of foreign currency commitments are consisting mostly of basis swaps related to location differ- initially recorded to deferred charges. Subsequently, the ences in prices. Notional contract amounts, excluding amounts are applied to the capitalized project cost on a unrealized gains and losses, were $4,397 million and percentage-of-completion basis, and are then amortized over $974 million at year-end 1998 and 1997. These amounts the lives of the applicable projects. At year-end 1998 and principally represent future values of contract volumes over 1997, net hedging gains of $50 million and $51 million, the remaining duration of outstanding swap contracts at the respectively, had yet to be amortized. respective dates. These contracts hedge a small fraction of Contracts to sell foreign currencies are primarily related our business activities, generally for the next twelve to a separately managed program to hedge the value of our months. Unrealized gains and losses on contracts outstand- investment portfolio denominated in foreign currencies. ing at year-end 1998 were $161 million and $140 million, Our strategy is to hedge the full value of this portion of our respectively. At year-end 1997, unrealized gains and losses investment portfolio and to close out forward contracts upon were $93 million and $58 million, respectively. the sale or maturity of the corresponding investments. We value these contracts at market based on the foreign TEXACO 1998 ANNUAL REPORT 67

Note 16 Other Financial Information, Commitments and Contingencies Environmental Liabilities able from Texaco Inc. The payment of dividends and pay- Texaco Inc. and subsidiary companies have financial liabili- ments on liquidation or redemption with respect to Series ties relating to environmental remediation programs which A, Series B and Series C are guaranteed by Texaco Inc. we believe are sufficient for known requirements. At The fixed dividend rate for Series A is 6-7/8% per December 31, 1998, the balance sheet includes liabilities of annum. The annual dividend rate for Series B averaged $285 million for future environmental remediation costs. 5.1% for 1998 and 5.9% for both 1997 and 1996. The div- Also, we have accrued $794 million for the future cost of idend rate on Series B is reset quarterly per contractual restoring and abandoning existing oil and gas properties. formula. Dividends on Series A and Series B are paid We have accrued for our probable environmental remedi- monthly. Dividends on Series A for 1998, 1997 and 1996 ation liabilities to the extent reasonably measurable. We totaled $24 million for each year. Annual dividends on based our accruals for these obligations on technical evalua- Series B totaled $6 million for 1998 and $7 million for both tions of the currently available facts, interpretation of 1997 and 1996. the regulations and our experience with similar sites. Series A and Series B are redeemable under certain cir- Additional accrual requirements for existing and new reme- cumstances and, at the option of Texaco Capital LLC (with diation sites may be necessary in the future when more facts Texaco Inc.’s consent) in whole or in part, from time to time, are known. The potential also exists for further legislation at $25 per share on or after October 31, 1998 for Series A which may provide limitations on liability. It is not possible and June 30, 1999 for Series B, plus, in each case, accrued to project the overall costs or a range of costs for environ- and unpaid dividends to the date fixed for redemption. mental items beyond that disclosed above. This is due to Dividends on Series C at a rate of 7.17% per annum, uncertainty surrounding future developments, both in rela- compounded annually, will be paid at the redemption date tion to remediation exposure and to regulatory initiatives. of February 28, 2005, unless earlier redemption occurs. However, while future environmental expenditures in the Early redemption may result upon the occurrence of certain petroleum industry are expected to be significant, they will specific events. be a cost of doing business that will have to be recovered in We have entered into an interest rate and currency swap the marketplace. Moreover, it is not believed that such future related to Series C preferred shares. The swap matures in the costs will be material to our financial position or to our year 2005. Over the life of the interest rate swap component operating results over any reasonable period of time. of the contract, we will make LIBOR-based floating rate interest payments based on a notional principal amount of Preferred Shares of Subsidiaries $65 million. Canadian dollar interest will accrue to us at a Minority holders own $602 million of preferred shares of fixed rate applied to the accreted notional principal amount, our subsidiary companies, which is reflected as minority which was Cdn. $87 million at the inception of the swap. interest in subsidiary companies in the Consolidated The currency swap component of the transaction calls for Balance Sheet. us to exchange at contract maturity date $65 million for MVP Production Inc., a subsidiary, has variable rate Cdn. $170 million, representing Cdn. $87 million plus cumulative preferred shares of $75 million owned by one accrued interest. The carrying amount of this contract rep- minority holder. The shares have voting rights and are resents the Canadian dollar accrued interest receivable by redeemable in 2003. Dividends on these shares were us. At year-end 1998 and 1997, the carrying amount and $4 million in 1998, 1997 and 1996. the fair value of this transaction were not material. Texaco Capital LLC, another subsidiary, has three classes Series A, Series B and Series C preferred shares are non- of preferred shares, all held by minority holders. The first voting, except under limited circumstances. class is 14 million shares totaling $350 million of The above preferred stock issues currently require annual Cumulative Guaranteed Monthly Income Preferred Shares, dividend payments of approximately $34 million. We are Series A (Series A). The second class is 4.5 million shares required to redeem $75 million of this preferred stock in totaling $112 million of Cumulative Adjustable Rate 2003, $65 million (plus accreted dividends of $59 million) Monthly Income Preferred Shares, Series B (Series B). The in 2005, $112 million in 2024 and $350 million in 2043. third class, issued in Canadian dollars, is 3.6 million shares We have the ability to extend the required redemption totaling $65 million of Deferred Preferred Shares, Series C dates for the $112 million and $350 million of preferred (Series C). Texaco Capital LLC’s sole assets are notes receiv- stock beyond 2024 and 2043. 68 TEXACO 1998 ANNUAL REPORT

Financial Guarantees Other Commitments We have guaranteed the payment of certain debt, lease com- During 1997, 1996 and 1995, we sold leasehold interests in mitments and other obligations of third parties and affiliate certain equipment not yet in service and received British companies. These guarantees totaled $797 million and pound payments totaling $530 million. Under a related $372 million at December 31, 1998 and 1997. The year- agreement, in 1997 we leased back these leasehold interests. end 1998 amount includes $387 million of operating lease We made a British pound payment in 1997, which released commitments of Equilon, our affiliate. us from future lease commitments under this agreement. Exposure to credit risk in the event of non-payment This payment effectively repurchased the leasehold interests by the obligors is represented by the contractual amount previously sold. of these instruments. No loss is anticipated under these guarantees. Litigation Additionally, in June 1997, our 50% owned affiliate, Texaco and approximately fifty other oil companies are Caltex Petroleum Corporation (Caltex), received a claim defendants in seventeen purported class actions. The actions from the United States Internal Revenue Service for are pending in Texas, New Mexico, Oklahoma, Louisiana, $292 million in excise taxes, $140 million in penalties and Utah, Mississippi and Alabama. The plaintiffs allege that the $1.6 billion in interest. The IRS claim relates to sales of defendants undervalued oil produced from properties leased crude oil by Caltex to Japanese customers beginning in 1980. from the plaintiffs by establishing artificially low selling Caltex believes that the underlying claim for excise taxes prices. They allege that these low selling prices resulted in and penalties is wrong and that the claim for interest is the defendants underpaying royalties or severance taxes flawed. We believe that this claim is without merit and is to them. Plaintiffs seek to recover royalty underpayments not anticipated to be materially important in relation to our and interest. In some cases plaintiffs also seek to recover consolidated financial position or results of operations. In severance taxes and treble and punitive damages. Texaco and February 1999, the original letter of credit to the IRS for twenty-four other defendants have executed a settlement $2.3 billion, which Caltex arranged in order to litigate this agreement with most of the plaintiffs that will resolve many claim, was increased to $2.5 billion. Texaco and its 50% of these disputes. The federal court in Texas has prelimi- partner, Chevron Corporation, have severally guaranteed narily approved the settlement and is considering final Caltex’ letter of credit obligation to a syndicate of banks. approval. Similar claims by the federal and various state governments remain unresolved. Throughput Agreements Texaco Inc. and certain of its subsidiary companies previ- ously entered into certain long-term agreements wherein we It is impossible for us to ascertain the ultimate legal and committed to ship through affiliated pipeline companies financial liability with respect to contingencies and com- and an offshore oil port sufficient volume of crude oil or mitments. However, we do not anticipate that the petroleum products to enable these affiliated companies to aggregate amount of such liability in excess of accrued lia- meet a specified portion of their individual debt obligations, bilities will be materially important in relation to our or, in lieu thereof, to advance sufficient funds to enable consolidated financial position or results of operations. these affiliated companies to meet these obligations. In 1998, we assigned the shipping obligations to Equilon, our affiliate, but Texaco remains responsible for deficiency pay- ments on virtually all of these agreements. Additionally, Texaco has entered into long-term purchase commitments with third parties for take or pay gas transportation. At December 31, 1998 and 1997, our maximum exposure to loss was estimated to be $500 million and $525 million. However, based on our right of counterclaim against Equilon and unaffiliated third parties in the event of non- performance, our net exposure was estimated to be $195 million and $422 million at December 31, 1998 and 1997. No significant losses are anticipated as a result of these obligations. TEXACO 1998 ANNUAL REPORT 69

Report of Management

We are responsible for preparing Texaco’s consolidated financial The Audit Committee is comprised of seven directors who are statements in accordance with generally accepted accounting not employees of Texaco. This Committee reviews and evaluates principles. In doing so, we must use judgment and estimates when Texaco’s accounting policies and reporting practices, internal the outcome of events and transactions is not certain. Information auditing, internal controls, security and other matters. The appearing in other sections of this Annual Report is consistent Committee also evaluates the independence and professional com- with the financial statements. petence of Arthur Andersen LLP and reviews the results and scope Texaco’s financial statements are based on its financial records. of their audit. The internal and independent auditors have free We rely on Texaco’s internal control system to provide us reason- access to the Committee to discuss financial reporting and internal able assurance that these financial records are being accurately and control issues. objectively maintained and that the company’s assets are being protected. The internal control system comprises: ➤ Corporate Conduct Guidelines that require all employees to obey all applicable laws, comply with company policies and main- tain the highest ethical standards in conducting company business, Peter I. Bijur ➤ An organizational structure in which responsibilities are Chairman of the Board and Chief Executive Officer defined and divided, and ➤ Written policies and procedures that cover initiating, review- ing, approving and recording transactions.

We require members of our management team to formally certify each year that the internal controls for their business units are Patrick J. Lynch operating effectively. Senior Vice President and Chief Financial Officer Texaco’s internal auditors review and report on the effectiveness of internal controls during the course of their audits. Arthur Andersen LLP, selected by the Audit Committee and approved by stockholders, independently audits Texaco’s financial statements. Arthur Andersen assesses the adequacy and effectiveness of Texaco’s internal controls when determining the nature, timing and scope Robert C. Oelkers of their audit. We seriously consider all suggestions for improving Vice President and Comptroller Texaco’s internal controls that are made by the internal and inde- pendent auditors.

Report of Independent Public Accountants

To the Stockholders, Texaco Inc.: We have audited the accompanying consolidated balance sheet of In our opinion, the financial statements referred to above pre- Texaco Inc. (a Delaware corporation) and subsidiary companies as sent fairly, in all material respects, the financial position of Texaco of December 31, 1998 and 1997, and the related statements of Inc. and subsidiary companies as of December 31, 1998 and 1997, consolidated income, cash flows, stockholders’ equity and nonowner and the results of their operations and their cash flows for each of changes in equity for each of the three years in the period ended the three years in the period ended December 31, 1998 in confor- December 31, 1998. These financial statements are the responsibil- mity with generally accepted accounting principles. ity of the company’s management. Our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits in accordance with generally accepted auditing standards. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit Arthur Andersen LLP includes examining, on a test basis, evidence supporting the February 25, 1999 amounts and disclosures in the financial statements. An audit also New York, N.Y. includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits pro- vide a reasonable basis for our opinion. 70 TEXACO 1998 ANNUAL REPORT

Supplemental Oil and Gas Information

The following pages provide information required by future investments are made in exploration and develop- Statement of Financial Accounting Standards No. 69, ment programs. Disclosures about Oil and Gas Producing Activities. ➤ Proved developed reserves are reserves that we expect to Table I – Net Proved Reserves be recovered through existing wells with existing equip- The reserve quantities include only those quantities that are ment and operating methods. recoverable based upon reasonable estimates from sound geological and engineering principles. As additional infor- ➤ Proved undeveloped reserves are reserves that we expect to mation becomes available, these estimates may be revised. be recovered from new wells on undrilled acreage, or from Also, we have a large inventory of potential hydrocarbon existing wells where a relatively major expenditure is resources that we expect will increase our reserve base, as required for completion of development.

Table I

Net Proved Reserves of Net Proved Reserves of Natural Gas Crude Oil and Natural Gas Liquids (Billions of Cubic Feet) (Millions of Barrels)

Consolidated Subsidiaries Equity Consolidated Subsidiaries Equity Affiliate Affiliate United Other Other – Other World- United Other Other – Other World- States West Europe East Total East wide States West Europe East Total East wide Developed reserves 1,125 52 142 413 1,732 350 2,082 3,666 522 452 84 4,724 140 4,864 Undeveloped reserves 216 2 208 62 488 88 576 396 325 492 3 1,216 15 1,231 As of December 31, 1995 1,341 54 350 475 2,220 438 2,658 4,062 847 944 87 5,940 155 6,095 Discoveries & extensions 82 4 80 29 195 1 196 436 263 34 3 736 15 751 Improved recovery 20 — — — 20 81 101 8 — — — 8 1 9 Revisions 44 2 6 21 73 (3) 70 (99) (1) 58 13 (29) — (29) Net purchases (sales) (23) — 3 (1) (21) — (21) (53) (7) — 1 (59) — (59) Production (142) (4) (42) (58) (246) (54) (300) (626) (71) (75) (4) (776) (18) (794) Total changes (19) 2 47 (9) 21 25 46 (334) 184 17 13 (120) (2) (122) Developed reserves 1,100 50 165 418 1,733 354 2,087 3,360 893 452 96 4,801 136 4,937 Undeveloped reserves 222 6 232 48 508 109 617 368 138 509 4 1,019 17 1,036 As of December 31, 1996* 1,322 56 397 466 2,241 463 2,704 3,728 1,031 961 100 5,820 153 5,973 Discoveries & extensions 107 13 34 61 215 4 219 692 26 92 346 1,156 2 1,158 Improved recovery 15 — 65 — 80 18 98 7 — 22 — 29 5 34 Revisions 55 3 11 100 169 22 191 228 75 41 (22) 322 19 341 Net purchases (sales) 413 (2) (31) (8) 372 — 372 10 (118) (7) (310) (425) — (425) Production (145) (5) (45) (66) (261) (56) (317) (643) (96) (81) (2) (822) (17) (839) Total changes 445 9 34 87 575 (12) 563 294 (113) 67 12 260 9 269 Developed reserves 1,374 54 210 463 2,101 354 2,455 3,379 792 576 110 4,857 145 5,002 Undeveloped reserves 393 11 221 90 715 97 812 643 126 452 2 1,223 17 1,240 As of December 31, 1997* 1,767 65 431 553 2,816 451 3,267 4,022 918 1,028 112 6,080 162 6,242 Discoveries & extensions 70 2 8 32 112 1 113 599 6 47 98 750 1 751 Improved recovery 136 — 16 3 155 156 311 4 — 7 — 11 3 14 Revisions 46 (15) 22 55 108 137 245 152 (12) (6) 34 168 10 178 Net purchases (sales) (38) — — 26 (12) — (12) (39) — — 250 211 — 211 Production (157) (4) (58) (71) (290) (61) (351) (633) (92) (112) (17) (854) (25) (879) Total changes 57 (17) (12) 45 73 233 306 83 (98) (64) 365 286 (11) 275 Developed reserves 1,415 39 246 490 2,190 456 2,646 3,345 688 615 374 5,022 135 5,157 Undeveloped reserves 409 9 173 108 699 228 927 760 132 349 103 1,344 16 1,360 As of December 31, 1998* 1,824 48 419 598 2,889 684 3,573 4,105 820a 964 477 6,366a 151 6,517a *Includes net proved NGL reserves (a) Additionally, there is approximately 586 BCF of natural As of December 31, 1996 207 1 54 1 263 6 269 gas in Other West which will be available from production As of December 31, 1997 246 — 71 — 317 4 321 during the period 2005-2016 under a long-term purchase associated with a service agreement. As of December 31, 1998 272 — 68 — 340 6 346 TEXACO 1998 ANNUAL REPORT 71

The following chart summarizes our experience in find- Table II – Standardized Measure ing new quantities of oil and gas to replace our production. The standardized measure provides a common benchmark Our reserve replacement performance is calculated by among those companies that have exploration and produc- dividing our reserve additions by our production. Our addi- ing activities. This measure may not necessarily match our tions relate to new discoveries, existing reserve extensions, view of the future cash flows from our proved reserves. improved recoveries and revisions to previous reserve The standardized measure is calculated at a 10% dis- estimates. The chart excludes oil and gas quantities from count. Future revenues are based on year-end prices for purchases and sales. liquids and gas. Future production and development costs are based on current year costs. Extensive judgement is used Worldwide United States International to estimate the timing of production and future costs over Year 1998 166% 144% 191% the remaining life of the reserves. Future income taxes are Year 1997 167% 132% 212% calculated using each country’s statutory tax rate. Year 1996 113% 83% 154% Our inventory of potential hydrocarbon resources, which 3 year average 150% 120% 187% may become proved in the future, are excluded. This could 5 year average 138% 113% 171% significantly impact our standardized measure in the future.

Table II – Standardized Measure of Discounted Future Net Cash Flows

Consolidated Subsidiaries Equity Affiliate – United Other Other Other (Millions of dollars) States West Europe East Total East Worldwide As of December 31, 1998 Future cash inflows from sale of oil & gas, and service fee revenue $ 23,147 $ 1,657 $ 6,581 $ 4,816 $ 36,201 $ 4,708 $ 40,909 Future production costs (10,465) (605) (2,574) (2,551) (16,195) (1,992) (18,187) Future development costs (4,055) (142) (1,695) (761) (6,653) (803) (7,456) Future income tax expense (2,583) (419) (715) (1,023) (4,740) (967) (5,707) Net future cash flows before discount 6,044 491 1,597 481 8,613 946 9,559 10% discount for timing of future cash flows (2,626) (244) (644) (167) (3,681) (391) (4,072) Standardized measure of discounted future net cash flows $ 3,418 $ 247 $ 953 $ 314 $ 4,932 $ 555 $ 5,487 As of December 31, 1997 Future cash inflows from sale of oil & gas, and service fee revenue $ 34,084 $ 2,305 $ 9,395 $ 7,690 $ 53,474 $ 5,182 $ 58,656 Future production costs (10,980) (807) (2,854) (2,303) (16,944) (1,840) (18,784) Future development costs (4,693) (132) (1,809) (749) (7,383) (476) (7,859) Future income tax expense (5,512) (652) (898) (3,445) (10,507) (1,519) (12,026) Net future cash flows before discount 12,899 714 3,834 1,193 18,640 1,347 19,987 10% discount for timing of future cash flows (5,361) (252) (1,424) (374) (7,411) (519) (7,930) Standardized measure of discounted future net cash flows $ 7,538 $ 462 $ 2,410 $ 819 $ 11,229 $ 828 $ 12,057 As of December 31, 1996 Future cash inflows from sale of oil & gas, and service fee revenue $ 41,807 $ 2,863 $11,242 $ 9,261 $ 65,173 $ 6,632 $ 71,805 Future production costs (8,080) (894) (2,368) (1,993) (13,335) (1,776) (15,111) Future development costs (2,790) (141) (2,094) (551) (5,576) (740) (6,316) Future income tax expense (10,444) (758) (1,946) (5,099) (18,247) (2,181) (20,428) Net future cash flows before discount 20,493 1,070 4,834 1,618 28,015 1,935 29,950 10% discount for timing of future cash flows (8,602) (458) (1,740) (489) (11,289) (695) (11,984) Standardized measure of discounted future net cash flows $ 11,891 $ 612 $ 3,094 $ 1,129 $ 16,726 $ 1,240 $ 17,966 72 TEXACO 1998 ANNUAL REPORT

Table III – Changes in the Standardized Measure The annual change in the standardized measure is measure due to change in price reflects the sharp drop in explained in this table by the major sources of change, crude oil and natural gas prices during 1998. discounted at 10%. ➤ Discoveries & extensions indicate the value of the new ➤ Sales & transfers, net of production costs capture the current reserves at year-end prices, less related costs. year’s revenues less the associated producing expenses. The ➤ Development costs incurred during the period capture the net amount reflected here correlates to Table VII for revenues current year’s development costs that are shown in less production costs. Table V. These costs will reduce the previously estimated ➤ Net changes in prices, production & development costs are future development costs. computed before the effects of changes in quantities. The ➤ Accretion of discount represents 10% of the beginning dis- beginning-of-the-year production forecast is multiplied counted future net cash flows before income tax effects. by the net annual change in the unit sales price and produc- tion cost. The large reduction in the 1998 standardized ➤ Net change in income taxes is computed as the change in present value of future income taxes.

Table III – Changes in the Standardized Measure

Worldwide Including Equity in Affiliate – Other East (Millions of dollars) 1998 1997 1996 Standardized measure – beginning of year $ 12,057 $ 17,966 $ 11,872 Sales of minerals-in-place (160) (79) (458) 11,897 17,887 11,414 Changes in ongoing oil and gas operations: Sales and transfers of produced oil and gas, net of production costs during the period (3,129) (4,921) (4,859) Net changes in prices, production and development costs (11,205) (14,632) 8,820 Discoveries and extensions and improved recovery, less related costs 728 2,681 3,182 Development costs incurred during the period 1,770 1,976 1,575 Timing of production and other changes (1,170) (969) (251) Revisions of previous quantity estimates 852 1,476 527 Purchases of minerals-in-place 48 449 138 Accretion of discount 1,916 3,027 1,952 Net change in discounted future income taxes 3,780 5,083 (4,532) Standardized measure – end of year $ 5,487 $ 12,057 $ 17,966

Table IV – Capitalized Costs Costs of the following assets are capitalized under the “success- quantities to be considered proved reserves) and uncom- ful efforts” method of accounting. These costs include the pleted exploratory well costs. activities of Texaco’s upstream operations but exclude the ➤ Support equipment and facilities include costs for seismic crude oil marketing activities, geothermal and other non- and drilling equipment, construction and grading equip- producing activities. As a result, this table will not correlate ment, repair shops, warehouses and other supporting assets to information in Note 7 to the financial statements. involved in oil and gas producing activities. ➤ Proved properties include mineral properties with proved ➤ The accumulated depreciation, depletion and amortization rep- reserves, development wells and uncompleted development resents the portion of the assets that have been charged to well costs. expense in prior periods. It also includes provisions for future ➤ Unproved properties include leaseholds under exploration restoration and abandonment activity. (even where hydrocarbons were found but not in sufficient TEXACO 1998 ANNUAL REPORT 73

Table IV – Capitalized Costs

Consolidated Subsidiaries Equity Affiliate – United Other Other Other (Millions of dollars) States West Europe East Total East Worldwide As of December 31, 1998 Proved properties $ 20,601 $ 515 $ 4,709 $ 1,799 $ 27,624 $ 1,015 $ 28,639 Unproved properties 1,188 53 71 390 1,702 408 2,110 Support equipment and facilities 437 27 37 342 843 768 1,611 Gross capitalized costs 22,226 595 4,817 2,531 30,169 2,191 32,360 Accumulated depreciation, depletion and amortization (14,140) (277) (3,381) (1,253) (19,051) (1,119) (20,170) Net capitalized costs $ 8,086 $ 318 $ 1,436 $ 1,278 $ 11,118 $ 1,072 $ 12,190 As of December 31, 1997 Proved properties $ 20,196 $ 581 $ 4,584 $ 1,623 $ 26,984 $ 1,112 $ 28,096 Unproved properties 1,248 16 89 225 1,578 338 1,916 Support equipment and facilities 438 26 37 228 729 578 1,307 Gross capitalized costs 21,882 623 4,710 2,076 29,291 2,028 31,319 Accumulated depreciation, depletion and amortization (13,849) (298) (3,135) (1,131) (18,413) (1,013) (19,426) Net capitalized costs $ 8,033 $ 325 $ 1,575 $ 945 $ 10,878 $ 1,015 $ 11,893

Table V – Costs Incurred This table summarizes how much we spent to explore and ➤ Exploration and development costs may be capitalized or develop our existing reserve base, and how much we spent expensed, as applicable. Such costs also include adminis- to acquire mineral rights from others (classified as proved trative expenses and depreciation applicable to support or unproved). equipment associated with these activities. As a result, the costs incurred will not correlate to Capital and ➤ Exploration costs include geological and geophysical Exploratory Expenditures. costs, the cost of carrying and retaining undeveloped prop- erties and exploratory drilling costs. On a worldwide basis, in 1998 we spent $3.45 for each BOE ➤ Development costs include the cost of drilling and equipping we added. Finding and development costs averaged $3.91 development wells and constructing related production for the three-year period 1996-1998 and $3.75 per BOE for facilities for extracting, treating, gathering and storing oil the five-year period 1994-1998. and gas from proved reserves. 74 TEXACO 1998 ANNUAL REPORT

Table V – Costs Incurred

Consolidated Subsidiaries Equity Affiliate – United Other Other Other (Millions of dollars) States West Europe East Total East Worldwide For the year ended December 31, 1998 Proved property acquisition $ 27 $ — $ — $ 199 $ 226 $ — $ 226 Unproved property acquisition 85 1 — 32 118 — 118 Exploration 417 92 65 277 851 19 870 Development 1,073 25 308 204 1,610 160 1,770 Total $ 1,602 $ 118 $ 373 $ 712 $ 2,805 $ 179 $ 2,984 For the year ended December 31, 1997 Proved property acquisition $ 1,099* $ — $ — $ — $ 1,099 $ — $ 1,099 Unproved property acquisition 527* 1 — 23 551 — 551 Exploration 480 15 59 234 788 18 806 Development 1,220 62 419 108 1,809 167 1,976 Total $ 3,326 $ 78 $ 478 $ 365 $ 4,247 $ 185 $ 4,432 For the year ended December 31, 1996 Proved property acquisition $ 56 $ — $ — $ — $ 56 $ — $ 56 Unproved property acquisition 91 5 — 20 116 — 116 Exploration 356 18 90 225 689 9 698 Development 827 107 384 113 1,431 144 1,575 Total $ 1,330 $ 130 $ 474 $ 358 $ 2,292 $ 153 $ 2,445

*Includes the acquisition of Monterey Resources on a net cost basis of $1,520 million, which is net of deferred income taxes amounting to $469 million and $245 million for the acquired proved and unproved properties, respectively.

Table VI – Unit Prices Average sales prices are calculated using the gross revenues (lifting) costs, other taxes and the depreciation, depletion in Table VII. Average production costs equal producing and amortization of support equipment and facilities.

Average sales prices Natural Natural Natural Crude oil gas per Crude oil gas per Crude oil gas per and NGL thousand and NGL thousand and NGL thousand Average production costs per barrel cubic feet per barrel cubic feet per barrel cubic feet (per composite barrel) 1998 1997 1996 1998 1997 1996 United States $ 10.14 $ 1.93 $ 16.32 $ 2.32 $ 16.97 $ 2.10 $ 4.07 $ 3.94 $ 3.82 Other West 9.65 .92 14.40 1.03 16.80 .96 1.86 2.80 3.44 Europe 11.73 2.42 18.41 2.42 20.37 2.47 5.24 5.58 5.95 Other East 9.61 .38 16.87 1.89 18.61 3.20 3.65 4.11 4.07 Affiliate – Other East 9.81 — 14.89 — 16.30 — 2.68 3.76 3.71

Table VII – Results of Operations Results of operations for exploration and production activities ➤ Revenues are based upon our production that is available consist of all the activities within our upstream operations, for sale and excludes revenues from resale of third party vol- except for crude oil marketing activities, geothermal and umes, equity earnings of certain smaller affiliates, trading other non-producing activities. As a result, this table will activity and miscellaneous operating income. Expenses are not correlate to the Analysis of Income by Operating Segments. associated with current year operations but do not include general overhead and special items. TEXACO 1998 ANNUAL REPORT 75

➤ Production costs consist of costs incurred to operate and undeveloped leaseholds and administrative expenses. Also maintain wells and related equipment and facilities. These included are taxes other than income taxes. costs also include taxes other than income taxes and admin- ➤ Depreciation, depletion and amortization includes the istrative expenses. amount for support equipment and facilities. ➤ Exploration costs include dry hole, leasehold impairment, ➤ Estimated income taxes are computed by adjusting each geological and geophysical expenses, the cost of retaining country’s income before income taxes for permanent differ- ences related to the oil and gas producing activities, then multiplying the result by the country’s statutory tax rate and adjusting for applicable tax credits.

Table VII – Results of Operations

Consolidated Subsidiaries Equity United Other Other Affiliate – (Millions of dollars) States West Europe East Total Other East Worldwide For the year ended December 31, 1998 Gross revenues from: Sales and transfers, including affiliate sales $ 2,570 $ — $ 438 $ 571 $ 3,579 $ 454 $ 4,033 Sales to unaffiliated entities 218 120 509 122 969 28 997 Production costs (1,066) (35) (400) (250) (1,751) (150) (1,901) Exploration costs (286) (31) (53) (137) (507) (16) (523) Depreciation, depletion and amortization (832) (22) (422) (113) (1,389) (106) (1,495) Other expenses (198) — (4) (10) (212) (1) (213) Results before estimated income taxes 406 32 68 183 689 209 898 Estimated income taxes (49) (14) (27) (166) (256) (102) (358) Net results $ 357 $ 18 $ 41 $ 17 $ 433 $ 107 $ 540 For the year ended December 31, 1997 Gross revenues from: Sales and transfers, including affiliate sales $ 3,492 $ — $ 495 $ 934 $ 4,921 $ 610 $ 5,531 Sales to unaffiliated entities 312 165 499 178 1,154 43 1,197 Production costs (986) (57) (323) (249) (1,615) (192) (1,807) Exploration costs (238) (10) (60) (195) (503) (16) (519) Depreciation, depletion and amortization (735) (27) (382) (129) (1,273) (110) (1,383) Other expenses (249) — — (24) (273) 9 (264) Results before estimated income taxes 1,596 71 229 515 2,411 344 2,755 Estimated income taxes (511) (40) (85) (418) (1,054) (173) (1,227) Net results $ 1,085 $ 31 $ 144 $ 97 $ 1,357 $ 171 $ 1,528 For the year ended December 31, 1996 Gross revenues from: Sales and transfers, including affiliate sales $ 3,383 $ — $ 524 $ 863 $ 4,770 $ 648 $ 5,418 Sales to unaffiliated entities 310 140 475 181 1,106 45 1,151 Production costs (937) (54) (321) (215) (1,527) (183) (1,710) Exploration costs (196) (27) (57) (150) (430) (8) (438) Depreciation, depletion and amortization (652) (24) (310) (107) (1,093) (110) (1,203) Other expenses (241) (1) (1) (40) (283) 8 (275) Results before estimated income taxes 1,667 34 310 532 2,543 400 2,943 Estimated income taxes (534) (26) (112) (417) (1,089) (212) (1,301) Net results $ 1,133 $ 8 $ 198 $ 115 $ 1,454 $ 188 $ 1,642 76 TEXACO 1998 ANNUAL REPORT

Supplemental Market Risk Disclosures

We use derivative financial instruments to hedge interest approximately $207 million. This would be offset by an rate, foreign currency exchange and market rate risks. opposite effect on the related hedged exposures. Derivatives principally include interest rate and/or currency swap contracts, forward and option contracts to buy and to Petroleum and Natural Gas Hedging sell foreign currencies, and commodity futures, options, In 1998, the notional amount of open derivative contracts swaps and other instruments. We hedge only a portion of increased by $3,423 million, mostly related to natural gas our risk exposures for assets, liabilities, commitments and hedging. future production, purchases and sales. We remain exposed For commodity derivatives permitted to be settled in on the unhedged portion of such risks. cash or another financial instrument, sensitivity effects are The estimated sensitivity effects below assume that valu- as follows. At year-end 1998, the aggregate effect of a hypo- ations of all items within a risk category will move in thetical 25% change in natural gas prices, a 15% change in tandem. This cannot be assured for exposures involving crude oil prices and a 16-21% change in petroleum product interest rates, currency exchange rates, petroleum and nat- prices (dependent on product and location) would not mate- ural gas. Users should realize that actual impacts from rially affect our consolidated financial position, net income future interest rate, currency exchange and petroleum and or cash flows. natural gas price movements will likely differ from the dis- closed impacts due to ongoing changes in risk exposure Investments in Debt and Publicly Traded levels and concurrent adjustments of hedging derivative Equity Securities positions. Additionally, the range of variability in prices and We are subject to price risk on this unhedged portfolio of rates is representative only of past fluctuations for each risk available-for-sale securities. During 1998, market risk expo- category. Past fluctuations in rates and prices may not neces- sure decreased by $129 million. At year-end 1998, a 10% sarily be an indicator of probable future fluctuations. appreciation or depreciation in debt and equity prices Notes 10, 15 and 16 to the financial statements include would change portfolio fair value by about $49 million. details of our hedging activities, fair values of financial instru- This assumes no fluctuations in currency exchange rates. ments, related derivatives exposures and accounting policies. Preferred Shares of Subsidiaries Debt and Debt-Related Derivatives We are exposed to interest rate risk on dividend require- We had variable rate debt of approximately $2.7 billion and ments of Series B preferred shares of Texaco Capital LLC. $2.0 billion at year-end 1998 and 1997, before effects of We are exposed to currency exchange risk on the related interest rate swaps. Interest rate swap notional Canadian dollar denominated Series C preferred shares of amounts at year-end 1998 decreased by less than $100 mil- Texaco Capital LLC. We are exposed to offsetting currency lion from year-end 1997. exchange risk as well as interest rate risk on a swap contract Based on our overall interest rate exposure on variable used to hedge the Series C. rate debt and interest rate swaps at December 31, 1998 Based on the above exposures, a hypothetical two per- (including the interest rate and equity swap), a hypothetical centage points increase or decrease in the applicable variable two percentage points increase or decrease in interest rates interest rates and a hypothetical 10% appreciation or depre- would not materially affect our consolidated financial posi- ciation in the Canadian dollar exchange rate would not tion, net income or cash flows. materially affect our consolidated financial position, net income or cash flows. Forward Exchange and Option Contracts In 1998, the net notional amount of open forward contracts Market Auction Preferred Shares (MAPS) increased by $831 million. This related mostly to hedging We are exposed to interest rate risk on dividend require- of increased balance sheet monetary exposures. ments of MAPS. A hypothetical two percentage points The effect on fair value of our forward exchange con- increase or decrease in interest rates would not materially tracts at year-end 1998 from a hypothetical 10% change in affect our consolidated financial position or cash flows. currency exchange rates would be an increase or decrease of There are no derivatives related to MAPS. TEXACO 1998 ANNUAL REPORT 77

Selected Financial Data

Selected Quarterly Financial Data

First Second Third Fourth First Second Third Fourth Quarter Quarter Quarter Quarter Quarter Quarter Quarter Quarter (Millions of dollars) 1998 1997 Revenues Sales and services $ 7,922 $ 7,729 $ 7,481 $ 7,778 $11,813 $10,983 $10,834 $11,557 Equity in income of affiliates, interest, asset sales and other 225 315 226 31 216 513 259 492 8,147 8,044 7,707 7,809 12,029 11,496 11,093 12,049 Deductions Purchases and other costs 6,114 5,972 5,836 6,257 9,298 8,671 8,355 8,906 Operating expenses 580 645 593 690 781 790 806 874 Selling, general and administrative expenses 276 296 290 362 419 417 450 469 Exploratory expenses 141 90 93 137 99 93 114 165 Depreciation, depletion and amortization 388 375 409 503 385 372 388 488 Interest expense, taxes other than income taxes and minority interest 249 240 237 233 261 247 220 272 7,748 7,618 7,458 8,182 11,243 10,590 10,333 11,174 Income (loss) before income taxes and cumulative effect of accounting change 399 426 249 (373) 786 906 760 875 Provision for (benefit from) income taxes 140 84 34 (160) (194) 335 270 252 Income (loss) before cumulative effect of accounting change 259 342 215 (213) 980 571 490 623 Cumulative effect of accounting change (25) — — — — — — — Net income (loss) $ 234 $ 342 $ 215 $ (213) $ 980 $ 571 $ 490 $ 623 Total nonowner changes in equity $ 264 $ 344 $ 210 $ (246) $ 939 $ 596 $ 476 $ 590

Net income (loss) per common share (dollars) Basic Income (loss) before cumulative effect of accounting change $ .46 $ .62 $ .38 $ (.43) $ 1.86 $ 1.07 $ .91 $ 1.15 Cumulative effect of accounting change (.05) — — — — — — — Net income (loss) $ .41 $ .62 $ .38 $ (.43) $ 1.86 $ 1.07 $ .91 $ 1.15 Diluted Income (loss) before cumulative effect of accounting change $ .46 $ .61 $ .38 $ (.43) $ 1.80 $ 1.05 $ .90 $ 1.12 Cumulative effect of accounting change (.04) — — — — — — — Net income (loss) $ .42 $ .61 $ .38 $ (.43) $ 1.80 $ 1.05 $ .90 $ 1.12

See accompanying notes to consolidated financial statements. 78 TEXACO 1998 ANNUAL REPORT

Five-Year Comparison of Selected Financial Data

(Millions of dollars) 1998 1997 1996 1995 1994 For the year: Revenues from continuing operations $ 31,707 $ 46,667 $ 45,500 $ 36,787 $ 33,353 Net income (loss) before cumulative effect of accounting changes Continuing operations $ 603 $ 2,664 $ 2,018 $ 728 $ 979 Discontinued operations — — — — (69) Cumulative effect of accounting changes (25) — — (121) — Net income $ 578 $ 2,664 $ 2,018 $ 607 $ 910 Total nonowner changes in equity $ 572 $ 2,601 $ 1,863 $ 592 $ 972 Net income (loss) per common share (dollars) Basic Income (loss) before cumulative effect of accounting changes Continuing operations $ 1.04 $ 4.99 $ 3.77 $ 1.29 $ 1.72 Discontinued operations — — — — (.14) Cumulative effect of accounting changes (.05) — — (.24) — Net income $ .99 $ 4.99 $ 3.77 $ 1.05 $ 1.58 Diluted Income (loss) before cumulative effect of accounting changes Continuing operations $ 1.04 $ 4.87 $ 3.68 $ 1.28 $ 1.72 Discontinued operations — — — — (.14) Cumulative effect of accounting changes (.05) — — (.23) — Net income $ .99 $ 4.87 $ 3.68 $ 1.05 $ 1.58 Cash dividends per common share (dollars) $ 1.80 $ 1.75 $ 1.65 $ 1.60 $ 1.60 Total cash dividends paid on common stock $ 952 $ 918 $ 859 $ 832 $ 830 At end of year: Total assets $ 28,570 $ 29,600 $ 26,963 $ 24,937 $ 25,505 Debt and capital lease obligations Short-term $ 939 $ 885 $ 465 $ 737 $ 917 Long-term 6,352 5,507 5,125 5,503 5,564 Total debt and capital lease obligations $ 7,291 $ 6,392 $ 5,590 $ 6,240 $ 6,481

See accompanying notes to consolidated financial statements. TEXACO 1998 ANNUAL REPORT 79

Texaco Inc. Board of Directors

Peter I. Bijur Sam Nunn COMMITTEES OF THE BOARD PUBLIC RESPONSIBILITY Chairman and Chief Partner COMMITTEE John Brademas, Chair Executive Officer King & Spalding EXECUTIVE COMMITTEE Texaco Inc. Atlanta, GA Peter I. Bijur, Chair Michael C. Hawley White Plains, NY Willard C. Butcher Franklyn G. Jenifer Charles H. Price, II Edmund M. Carpenter Sam Nunn A. Charles Baillie Former Chairman Franklyn G. Jenifer Robin B. Smith Chairman and Chief Mercantile Bank of Charles H. Price, II William C. Steere, Jr. Executive Officer Kansas City Robin B. Smith Toronto-Dominion Bank Kansas City, MO Thomas A. Vanderslice FINANCE COMMITTEE Toronto, Canada Peter I. Bijur, Chair A. Charles Baillie Charles R. Shoemate COMMITTEE OF NON- John Brademas Chairman, President and MANAGEMENT DIRECTORS Mary K. Bush President Emeritus Chief Executive Officer William Wrigley, Chair Willard C. Butcher New York University Bestfoods All non-management Edmund M. Carpenter New York, NY Englewood Cliffs, NJ Directors Charles H. Price, II William Wrigley Mary K. Bush Robin B. Smith AUDIT COMMITTEE President Chairman and Chief Thomas A. Vanderslice, Chair Bush & Company Executive Officer John Brademas Washington, DC Publishers Clearing House Michael C. Hawley Port Washington, NY Franklyn G. Jenifer Willard C. Butcher Sam Nunn Former Chairman and Chief William C. Steere, Jr. Charles R. Shoemate Executive Officer Chairman and Chief Robin B. Smith The Chase Manhattan Executive Officer Bank, N.A. Pfizer Inc. COMMITTEE ON DIRECTORS AND BOARD GOVERNANCE New York, NY New York, NY Robin B. Smith, Chair Willard C. Butcher Edmund M. Carpenter Thomas A. Vanderslice Edmund M. Carpenter President and Chief Private Investor Thomas A. Vanderslice Executive Officer Boston, MA William Wrigley Barnes Group, Inc. Bristol, CT William Wrigley PENSION COMMITTEE President and Chief Charles H. Price, II, Chair Michael C. Hawley Executive Officer Mary K. Bush Chairman and Chief Wm. Wrigley Jr. Company William C. Steere, Jr. Executive Officer (designate) Chicago, IL William Wrigley The Gillette Company Boston, MA COMPENSATION COMMITTEE Willard C. Butcher, Chair Franklyn G. Jenifer Edmund M. Carpenter President Michael C. Hawley University of Texas at Dallas Charles H. Price, II Dallas, TX William C. Steere, Jr. Thomas A. Vanderslice 80 TEXACO 1998 ANNUAL REPORT

Texaco Inc. Officers

Peter I. Bijur Stephen M. Turner Claire S. Farley Robert A. Solberg Chairman of the Board and Senior Vice President Vice President Vice President Chief Executive Officer Exploration & New Ventures Commercial Development William M. Wicker C. Robert Black Senior Vice President James R. Metzger Janet L. Stoner Senior Vice President Corporate Development Vice President Vice President Corporate Planning & Human Resources Patrick J. Lynch Clarence P. Cazalot, Jr. Economics Senior Vice President and Vice President Kjestine M. Anderson Chief Financial Officer Production Operations Robert C. Oelkers Secretary and Vice President and Corporate Communications John J. O’Connor Eugene Celentano Comptroller Senior Vice President Vice President Michael N. Ambler Worldwide Exploration & International Marketing & Deval L. Patrick General Tax Counsel Production Manufacturing Vice President and General Counsel James F. Link Glenn F. Tilton Treasurer Senior Vice President Elizabeth P. Smith Global Businesses Vice President Investor Relations & Shareholder Services

Changes

➤ Carl B. Davidson, Vice President and Secretary of Texaco Inc., retired on May 1, 1998, after 33 years of ser- vice. He reached the company’s normal retirement age.

➤ Kjestine M. Anderson was elected as Secretary of Texaco Inc., effective May 1, 1998.

➤ Deval L. Patrick joined the company as a Vice President and General Counsel of Texaco Inc., effective February 8, 1999.

➤ David C. Crikelair, Vice President of Texaco Inc., resigned effective February 25, 1999, to join Equilon Enterprises LLC as Chief Financial Officer. TEXACO 1998 ANNUAL REPORT. 81

Investor Information

Common Stock — Market and Dividend Information: Texaco Inc. common stock (symbol TX) is traded princi- Texaco’s common stock price reached a high of $65.00, and pally on the New York Stock Exchange. As of February 25, closed December 31, 1998, at $53.00. 1999, there were 209,728 shareholders of record. In 1998,

Common Stock Price Range High Low High Low Dividends 1998 1997* 1998 1997*

First Quarter $ 65 $ 491⁄16 $ 553⁄4 $ 487⁄8 $ .45 $ .425 Second Quarter 633⁄4 553⁄4 577⁄16 501⁄2 .45 .425 Third Quarter 647⁄8 551⁄4 6111⁄16 5411⁄32 .45 .45 Fourth Quarter 637⁄8 501⁄4 637⁄16 511⁄8 .45 .45

*Reflects two-for-one stock split, effective September 29, 1997.

Stock Transfer Agent and SECURITY ANALYSTS AND INSTITUTIONAL Shareholder Communications INVESTORS SHOULD CONTACT: Elizabeth P. Smith FOR INFORMATION ABOUT TEXACO OR ASSISTANCE WITH YOUR ACCOUNT, Vice President, Texaco Inc. PLEASE CONTACT: Phone: (914) 253-4478 Texaco Inc. Fax: (914) 253-6269 Investor Services E-mail: [email protected] 2000 Westchester Avenue White Plains, NY 10650-0001 Annual Meeting Phone: 1-800-283-9785 Texaco Inc.’s Annual Shareholders Meeting will be held at Fax: (914) 253-6286 the Rye Town Hilton, Rye Brook, NY, on Tuesday, April 27, E-mail: [email protected] 1999. A formal notice of the meeting, together with a proxy statement and proxy form, is being mailed to share- NY Drop Agent holders with this report. ChaseMellon Shareholder Services 120 Broadway – 13th Floor Investor Services Plan New York, NY 10271 The company’s Investor Services Plan offers a variety of Phone: (212) 374-2500 benefits to individuals seeking an easy way to invest in Fax: (212) 571-0871 Texaco Inc. common stock. Enrollment in the Plan is open to anyone, and investors may make initial investments Co-Transfer Agent directly through the company. The Plan features dividend Montreal Trust Company reinvestment, optional cash investments and custodial ser- 151 Front Street West – 8th Floor vice for stock certificates. Texaco’s Investor Services Plan is Toronto, Ontario, Canada M5J 2N1 an excellent way to start an investment program for family Phone: 1-800-663-9097 or friends. For a complete informational package, includ- Fax: (416) 981-9507 ing a Plan prospectus, call 1-800-283-9785, e-mail at [email protected], or visit Texaco’s Internet home page at www.texaco.com. 82 TEXACO 1998 ANNUAL REPORT

Publications for Shareholders In addition to the Annual Report, Texaco issues several financial and informational publications which are available free of charge to interested shareholders on request from Investor Services: Texaco Inc.’s 1998 Annual Report on Form 10-K filed with the U.S. Securities and Exchange Commission. Financial and Operational Supplement – Comprehensive data on Texaco’s 1998 activities. Equal Opportunity and Diversity: 1998 Report From Texaco – A description of Texaco’s programs that foster equal employ- ment opportunity. Equality and Fairness Task Force Report – A report on Texaco’s human resources programs. Safety, Health, and Environment Review – A report on Texaco’s programs, policies and results in the areas of safety, health and environment is available on Texaco’s Internet site at www.texaco.com.

The use in this report of the term Texaco Inc. refers solely to Texaco Inc., a Delaware corporation. The use of such terms as Texaco, company, division, unit, organization, we, us, our and its, when referring either to Texaco Inc. and its consolidated subsidiaries or to subsidiaries and affiliates either indi- vidually or collectively, is only for convenience and is not intended to describe legal relationships. Texaco Inc.’s significant subsidiaries are listed as an exhibit to Texaco Inc.’s Annual Report on Form 10-K filed with the Securities and Exchange Commission.

This Annual Report is printed on recycled paper.

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